the honorable marsha j. pechman - stanford...

Case 2:08-cv-01008-MJP Document 174 Filed 10/14/11 of 3

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

The Honorable Marsha J. Pechman

UNITED STATES DISTRICT COURT WESTERN DISTRICT OF WASHINGTON

AT SEATTLE

CLAUDE A. REESE, et al.,

[PROPOSED] ORDER ON PLAINTIFFS’ MOTION TO FILE A SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT FOR VIOLATIONS OF THE FEDERAL SECURITIES LAWS

The Court, having received and reviewed Plaintiffs’ Motion to File A Second Amended

Consolidated Class Action Complaint For Violations of the Federal Securities Laws, makes the

following ruling:

The motion is hereby GRANTED. Plaintiffs may file the Second Amended

Consolidated Class Action Complaint For Violations of the Federal Securities Laws.

DATED this day of , 2011.

HONORABLE MARSHA J. PECHMAN United States District Court Judge

[PROPOSED] ORDER

(C08-1008 MJP)

KIPLING LAW GROUP PLLC 3601 F REMONT AVE N, SUITE 414

S EATTLE , WASHINGTON 98103 telephone (206) 545-0345

fax (206) 545-0350

Plaintiffs,

v.

ROBERT A. MALONE, et al.,

Defendants.

) ) ) ) ) ) ) ) ) ) )

Case No. C08-1008 MJP


1 Presented by:

s/ Javier Bleichmar Thomas A. Dubbs (admitted pro hac vice) Javier Bleichmar (admitted pro hac vice) Erin H. Rump (admitted pro hac vice) LABATON SUCHAROW LLP 140 Broadway New York, NY 10005 212-907-0700 (tel) 212-818-0477 (fax) [email protected] [email protected] [email protected]

Robert D. Stewart, WSBA #8998 Timothy M. Moran, WSBA #24925 KIPLING LAW GROUP PLLC 3601 Fremont Avenue N., Suite 414 Seattle, WA 98103 206.545.0345 (tel) 206.545.0350 (fax) [email protected] [email protected]

Counsel for Lead Plaintiffs

PLAINTIFFS’ MOTION TO FILE A SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT (C08-1008 MJP)

2 KIPLING LAW GROUP PLLC 3601 FREMONT AVE N, SUITE 414

SEATTLE , WASHINGTON 98103 telephone (206) 545-0345

fax (206) 545-0350

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27


CERTIFICATE OF SERVICE

I hereby certify that on the 14th day of October, 2011, I electronically filed the foregoing

with the Clerk of the Court using the CM/ECF system which will send notification of such filing

to the following:

• Timothy Michael Moran [email protected] [email protected]

• Richard C Pepperman, II [email protected]

• Steven J Purcell [email protected]

• Erin H. Rump [email protected] [email protected]

• Robert D Stewart [email protected]

• Stefanie J Sundel [email protected]

• John L Warden [email protected] [email protected]

s/ Javier Bleichmar Thomas A. Dubbs (admitted pro hac vice) Javier Bleichmar (admitted pro hac vice) Erin H. Rump (admitted pro hac vice) LABATON SUCHAROW LLP 140 Broadway New York, NY 10005 212-907-0700 (tel) 212-818-0477 (fax) [email protected] [email protected] [email protected]

KIPLING LAW GROUP PLLC 3601 F REMONT AVE N, SUITE 414

S EATTLE , WASHINGTON 98103 telephone (206) 545-0345

fax (206) 545-0350

• Peter A Binkow [email protected]

• Javier Bleichmar [email protected]

• Thomas A Dubbs [email protected]

• Neal A Dublinsky [email protected]

• Elizabeth K Ehrlich [email protected]

• Jonathan Gardner [email protected] [email protected]

• David C Lundsgaard [email protected] [email protected]

• Diane L McGimsey [email protected] s&[email protected]

DATED this 14th day of October, 2011.

[PROPOSED] ORDER

(C08-1008 MJP)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

THE HONORABLE MARSHA J. PECHMAN

UNITED STATES DISTRICT COURTWESTERN DISTRICT OF WASHINGTON

AT SEATTLE

CLAUDE A. REESE, Individually and on Behalf of All Others Similarly Situated,

Plaintiff,

v.

JOHN BROWNE and ROBERT MALONE

Defendants.

)))))))))))))))

No. C08-1008 MJP

SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT FOR VIOLATIONS OF THE FEDERAL SECURITIES LAWS

JURY TRIAL DEMANDED

Thomas A. Dubbs (admitted Pro Hac Vice)Javier Bleichmar (admitted Pro Hac Vice)Erin H. Rump (admitted Pro Hac Vice)LABATON SUCHAROW LLP140 BroadwayNew York, New York 10005Tel: 212.907.0700Fax: 212.818.0477

Robert D. Stewart, WSBA #8998Timothy M. Moran, WSBA #24925KIPLING LAW GROUP PLLC3601 Fremont Avenue N., Suite 414Seattle, WA 98103Tel: 206.545.0345Fax: 206.545.0350

Lead Counsel for Lead Plaintiffs Liaison Counsel for Lead Plaintiffs

October 14, 2011

Case 2:08-cv-01008-MJP Document 174-1 Filed 10/14/11 Page 1 of 73

SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT i

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

TABLE OF CONTENTS

Page

I. NATURE OF THE ACTION ............................................................................................ 1

II. JURISDICTION AND VENUE ........................................................................................ 4

III. THE PARTIES................................................................................................................... 4

IV. BP’S ADR AND COMMON STOCK ARE LISTED AND REGISTERED IN THE UNITED STATES .................................................................................................... 5

V. BACKGROUND ............................................................................................................... 7

A. The Trans Alaska Pipeline And The Oil Transit Lines .............................................. 7

B. Maintenance of Oil Pipelines – “Pigging” ................................................................. 8

VI. SUBSTANTIVE ALLEGATIONS ................................................................................... 9

A. BPXA Knew Years Prior To The Spills That The Failed Oil Transit Lines Were Subject To Highly Corrosive Conditions................................................ 9

B. BP Suppressed An Independent Report Showing Ineffective Corrosion Monitoring And Ignored Recommendations to Pig ................................ 11

C. BP’s Board Of Directors Knew Of The Widespread Corrosion At Prudhoe Bay In 2004 ................................................................................................ 14

D. BPXA Knew In September 2005 That The Corrosion Level In The Pipeline That Failed In March 2006 Was “High” .................................................... 15

E. BPXA Failed To Pig Despite Knowing Of Water And Sediment Buildup And Increased Corrosion, And Despite A Consensus And Internal Documents Establishing That Pigging Must Be Part Of Any “Sound” or “World Class” Corrosion Monitoring System....................................... 17

F. The March 2, 2006 Oil Spill..................................................................................... 19

G. Defendants Intentionally, or With Deliberate Recklessness, Ignored the Government’s Corrective Action Order Issued After The March 2 Oil Spill, Leading To The August Shutdown........................................................... 20

1. The March 15, 2006 Corrective Action Order.................................................. 20

(a) The CAO Raised Serious Concerns...................................................... 20

(b) The WOA and EOA Pipelines Had Similar Characteristics and Corrosive Conditions ..................................................................... 21

2. BP’s Board Was Informed That There Was A Risk of Additional Leaks In May 2006 ........................................................................................... 23


SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT ii

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

3. Hayward Knew That BPXA Had Violated The CAO ...................................... 23

4. Amendment No. 1 To The CAO....................................................................... 24

H. The August 7, 2006 Shutdown of Prudhoe Bay....................................................... 25

I. Amendment No. 2 To The CAO .............................................................................. 28

J. Congressional Hearings And Investigation .............................................................. 30

1. The Head Of The Corrosion Division Takes The Fifth .................................... 31

2. PHMSA Testified That BP’s Conduct Was Mystifying and Violated The Industry Standard of Care ........................................................... 31

3. The President of Alyeska Pipelines Testified That He Was Unaware Of Any Oil Pipeline Comparable To The EOA and WOA Lines That Were Not Pigged .................................................................. 32

4. The Senate Hearing........................................................................................... 32

5. The Congressional Investigation....................................................................... 33

K. Amendment No. 3 To The CAO .............................................................................. 34

L. BPXA Pled Guilty To A Criminal Violation Resulting From The Corrosion And Oil Spills In 2006............................................................................. 34

M. DOJ Filed A Civil Lawsuit On March 31, 2009, Based On BPXA’s Violations of The CAO ............................................................................................ 35

1. The DOJ Complaint (Filed After Plaintiffs’ 2008 Complaint) ......................... 35

2. The DOJ Consent Decree (Filed After Plaintiffs’ 2008 Complaint) ........................................................................................................ 37

N. The State of Alaska Sued BPXA After Plaintiffs’ 2008 Complaint Because The Corrosion Monitoring And Management System Violated State Law And Regulations ....................................................................... 38

1. BPXA’s Failure To Comply With Its Spill Prevention Plan Violated State Law............................................................................................ 38

2. The Leak Detection System .............................................................................. 41

(a) The Leak Detection System Violated Alaska State Law And Regulations ........................................................................................... 41

(b) Defendants Knew Or Were Deliberately Reckless In Not Knowing That The Leak Detection System Violated Alaska Laws and Regulations........................................................................... 42

VII. CLASS ACTION ALLEGATIONS ................................................................................ 42

VIII. FRAUD ON THE MARKET PRESUMPTION OF RELIANCE................................... 44


SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT iii

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

IX. SCIENTER ...................................................................................................................... 45

X. LOSS CAUSATION........................................................................................................ 47

XI. INAPPLICABILITY OF STATUTORY SAFE HARBOR ............................................ 51

XII. CAUSES OF ACTION.................................................................................................... 51

COUNT I Violation of § 10(b) of the Exchange Act And Rule 10b-5 Promulgated Thereunder Against BP, BPXA, Johnson, and Browne ............................. 51

A. Materially False And Misleading Statements And Omissions................................. 51

1. BP’s 2005 False And Misleading Statements and Omissions Concerning Compliance With “Best Environmental Practices”....................... 51

2. False and Misleading Statements and Omissions By Johnson On Behalf Of BPXA After March 2, 2006 About The Level Of Corrosion And Subsequent Efforts To Avoid Another Spill ............................ 53

(a) Defendant Johnson Falsely Claimed That The Corrosion Was Low And Manageable........................................................................... 53

(b) Johnson Falsely Claimed That The Highly Corrosive Conditions Were Unique To The WOA Line....................................... 54

(c) Johnson Falsely Claimed That No Other OTL Had The Same Combination Of Factors........................................................................ 55

3. Browne’s False and Misleading Statements and Omissions On Behalf of BP After March 2006 About Corrosion And Efforts To Avoid Another Spill .......................................................................................... 56

(a) The Corrosion Monitoring And Leak Detection Systems Were Not World Class And Violated Alaska’s Laws And Regulations ........................................................................................... 56

(i) The Corrosion Monitoring System Was NOT World Class.......................................................................................... 57

(ii) The Leak Detection System Was NOT World Class................ 58

(iii) The Corrosion Monitoring And Leak Detection Systems Violated Alaska’s Laws And Regulations ................................ 58

4. BP’s False And Misleading Statements and Omissions About Compliance With Environmental Laws And Regulations................................ 59

5. BP’s 2006 False And Misleading Statements and Omissions About Compliance With “Best Environmental Practices” ............................... 59

COUNT II Violations of § 10(b) of the Exchange Act and Rule 10b-5(a) and (c) Promulgated Thereunder Against BPXA ........................................................... 61


SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT iv

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

COUNT III Violations of § 20(a) of the Exchange Act Against BP, Browne, and Johnson ....................................................................................................... 64

JURY DEMAND......................................................................................................................... 66



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

The City of Edinburgh Council as Administering Authority of the Lothian Pension Fund

(“Lothian”), Bankinter Gestión de Activos, S.G.I.I.C. (“BGA”), Frankfurt Trust Investment-

Gesellschaft mbH (“Frankfurt Trust”), Frankfurter-Service Kapitalanglage-Gesellschaft mbH

(“Frankfurter Service”), and Pipefitters Local Union #537 Trust Funds (“Pipefitters #537”)

(collectively, “Lead Plaintiffs”) allege the following based upon the investigation of Lead

Counsel, which included a review of documents produced by Defendants.

I. NATURE OF THE ACTION

1. This is a class action on behalf of all persons who purchased or otherwise

acquired BP p.l.c. (“BP” or the “Company”) ordinary shares or American Depositary Receipts

(“ADRs”) during the period June 30, 2005 through August 4, 2006, inclusive (the “Class

Period”), with certain exceptions that are noted below (the “Class”).

2. This action alleges that Defendants (defined below) intentionally, and/or with

deliberate recklessness, failed to disclose the foreseeable risk that oil production at Prudhoe Bay,

Alaska would have to be shutdown, or dramatically curtailed, because the pipelines were

severely corroded as a result of BP’s substandard maintenance and monitoring practices,

ultimately found to be severely criminal.

3. On March 2, 2006, BP discovered that a leak in a pipeline in the Western

Operating Area of Prudhoe Bay (“WOA”) had caused a massive spill of more than 200,000

gallons of oil. The spill covered more than 2 acres of tundra and was by far the largest

ecological disaster caused by a failed pipeline in the history of oil exploration in Alaska. The

magnitude of the damage to the environment caused public furor. Congress launched an

investigation. The Department of Transportation intervened immediately into the operation,

maintenance, and inspection of BP’s pipelines in Prudhoe Bay. And the State of Alaska’s

environmental agency ordered that BP conduct an investigation of the cause of the spill.

4. In response to this sudden, intense governmental scrutiny, BP assured the public

that the March 2 spill was an anomaly and that BP was taking all necessary measures to prevent

another leak. On May 14, 2006, Defendant Maureen L. Johnson (“Johnson”), Senior Vice


SECOND AMENDED CONSOLIDATED CLASS ACTION COMPLAINT 2

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

President of BP Exploration (Alaska), Inc. (“BPXA”), granted an interview to a specialized

industry publication called Petroleum News. In the interview, Defendant Johnson said that

(i) BP had started taking a series of steps to ensure that another pipeline leak does not occur,

(ii) the pipeline that had caused the leak was different than the other pipelines at Prudhoe Bay

(iii) the Company had conducted 2,000 pipeline inspections at Prudhoe Bay since the leak, and

(iv) in the future, BP would inspect the inside of the pipelines on a regular basis.

5. On Sunday August 6, 2006, BP announced that it had discovered multiple leaks in

another pipeline, in a different area of Prudhoe Bay (the Eastern Operating Area (“EOA”)),

which had caused a new spill of approximately 1,000 gallons of oil. BP had also identified a

number of areas in the pipeline that were severely corroded. In response, BP shut down its entire

production from Prudhoe Bay of about 400,000 barrels a day, or 8 percent of the entire U.S. oil

production.

6. The news of the shutdown caused the price of oil to surge more than $2 a barrel

on August 7, 2006, and the U.S. government to announce that it would tap its strategic oil

reserves, if necessary, in an effort to calm the financial markets. At a time of then-record oil

prices of about $75 a barrel, the news of a production shortage of 400,000 barrels of oil a day, for

an indefinite amount of time, caused serious concern. BP’s ordinary shares and ADRs declined

substantially and BP lost billions of dollars in market capitalization.

7. The Prudhoe Bay shutdown gave new impetus to the numerous investigations into

BP’s pipeline operations that had been launched after the March 2, 2006 spill – investigations by

Congress, the U.S. Department of Justice (“DOJ”), federal and state agencies, and the press. The

results of all these investigations now show that BP knowingly, or with deliberate recklessness,

failed to properly maintain, operate, inspect, and monitor its pipelines at Prudhoe Bay. As set

forth in detail below, BP had received repeated warnings from multiple sources and knew that its

pipelines were severely corroded, repeatedly cut corrosion-inhibiting maintenance in order to

reduce costs and improve profits, and failed for more than 14 years to inspect the inside of the

pipelines with an in-line inspection tool that would have precisely identified the level and



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

location of corrosion.

8. As a result of this conduct, on October 24, 2007, BPXA pleaded guilty to a

criminal violation of the federal Clean Water Act. BPXA also agreed to pay a $20 million fine

in settlement of federal and state criminal violations. In the plea agreement, BPXA admitted that

(i) it knew in 2005 that corrosion activity had increased in the WOA pipeline that failed in March

2006; (ii) it knew that it had not pigged (either maintenance or smart) the WOA pipeline in

almost a decade; (iii) it knew that the EOA pipeline that failed in August 2006 was riddled with

sediment and deposits; (iv) it knew that the EOA pipeline had not been cleaned or inspected in

over 14 years; and (v) despite all of these known risks, it failed to expend sufficient resources to

combat corrosion.

9. In light of this criminal conduct, BPXA “agree[d] to freely and openly

acknowledge responsibility for its acts and omissions, and the acts and omissions of its

employees and agents, that constitute the agreed upon factual basis for its guilty plea in this

Agreement.”

10. On March 31, 2009, DOJ and the State of Alaska filed two new civil lawsuits

against BPXA seeking damages and injunctive relief as a result of the March and August 2006

spills. The DOJ Action alleged that BPXA violated the Federal Pipelines Safety Laws when it

disobeyed the federal government’s March 15, 2006 order to immediately take preventive and

corrective measures. BPXA and DOJ entered into a Consent Decree in July 2011 settling the

action.

11. The Alaska suit asserts that BPXA’s corrosion monitoring and leak detection

systems violated state laws and regulations – the same systems that immediately after the March

spill Defendant Browne falsely claimed were “world class” and operated in compliance with

Alaska’s laws and regulations.

12. The filing of the lawsuits by DOJ and Alaska, together with BPXA’s criminal

guilty plea, mark the culmination of yet another dark chapter in BP’s corporate history – one in

which BP failed to disclose the foreseeable risk that its severely corroded pipelines at Prudhoe



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

Bay would require the shutdown, and substantial reduction, of the field’s production activities.

II. JURISDICTION AND VENUE

13. This Court has subject matter jurisdiction over this action pursuant to Section 27

of the Securities and Exchange Act of 1934 (“Exchange Act”), 15 U.S.C. § 78a(a) and 28 U.S.C.

§ 1331. The claims asserted herein arise under Sections 10(b) and 20(a) of the Exchange Act as

amended, 15 U.S.C. §§ 78b(b) and 78t(a), and Rule 10b-5, 17 C.F.R. § 240, 10b-5, promulgated

thereunder.

14. Venue is proper in this District. In connection with the acts, conduct, and other

wrongs alleged in this complaint, Defendants, directly and indirectly, used the means and

instrumentalities of interstate commerce, including the mail and telephone communications.

III. THE PARTIES

15. Lead Plaintiffs purchased BP’s ordinary shares and/or ADRs during the Class

Period, and were damaged as a result of Defendants’ misconduct.

16. Defendant BP is a public limited company created in 1998 by the merger between

the Amoco Corporation and the British Petroleum Company p.l.c. Partly due to Prudhoe Bay,

BP is currently the largest oil and gas producer in the U.S. and the largest non-U.S. based

company listed on the New York Stock Exchange (“NYSE”). About 40% of BP’s fixed assets

are located in the U.S. BP is also the second largest refiner and fuel and gasoline marketer in

this country under the BP and Amoco brands, and the second largest liquid pipeline company

with approximately 10,000 miles of pipelines.

17. Defendant BPXA, a wholly-owned subsidiary of BP, is a Delaware corporation

with its principal place of business in Anchorage, Alaska. BPXA has more than 1,800

employees and oil and gas interests in Prudhoe Bay.

18. Defendant John Browne (“Browne”) was the Chief Executive of BP during the

Class Period. Browne retired on August 1, 2007, one year earlier than expected. Dr. Anthony B.

Hayward (“Hayward”) succeeded Browne as Chief Executive Officer.

19. Defendant Johnson was BPXA’s Senior Vice President and Greater Prudhoe Bay



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

Performance Unit Leader during the Class Period. As Senior Vice President of BPXA,

Defendant Johnson was responsible for the public information provided by BPXA.

20. Defendants Browne and Johnson are collectively referred to herein as the

“Individual Defendants.” BP and BPXA are collectively referred to herein as the “Corporate

Defendants.” The Corporate and the Individual Defendants are collectively referred to herein as

“Defendants.”

21. BP and the Individual Defendants influenced and caused BPXA to engage in the

unlawful conduct complained of herein.

22. During the Class Period, Defendants made public statements regarding the

operation of Prudhoe Bay, the maintenance and condition of pipelines at Prudhoe Bay, and

production at Prudhoe Bay. Defendants had a duty to promptly disseminate complete, truthful,

and accurate information and to promptly correct any public statements that had become

materially false or misleading. Defendants had access to internal documents, reports and other

information, including adverse non-public information concerning Prudhoe Bay operations,

maintenance and business which directly affected the interests of investors in BP’s ordinary

shares and ADRs.

23. The Individual Defendants named herein, by reason of their status as senior

executives, have at all relevant times had the power and influence, and did in fact control and

influence and cause or allow, BP and BPXA to engage in the unlawful acts and conduct

complained of herein. Each of the Defendants is liable as a direct participant in, or responsible

for, the wrongs complained of herein.

IV. BP’S ADR AND COMMON STOCK ARE LISTED AND REGISTERED IN THE UNITED STATES

24. In the United States, BP’s securities are traded in the form of American

Depository Shares (“ADSs”). JPMorgan Chase Bank, N.A. (“JPMorgan”) is the depositary and

transfer agent. Each ADS represents six ordinary shares of BP. BP’s ADSs are listed on the

NYSE. The ADSs are evidenced by American Depositary Receipts (“ADRs”).

25. BP’s ADSs (as evidenced by ADRs) have been listed on the NYSE since



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

approximately March 23, 1970. As of February 18, 2011, BP had 814,755,024 ADSs (equivalent

to approximately 4,888,530,144 ordinary shares) outstanding, which were held by approximately

114,834 ADS holders. Of these, approximately 113,490 had registered addresses in the United

States as of February 18, 2011. One of the registered holders of ADSs represents some 795,382

underlying holders.

26. The 814,766,024 ADSs outstanding represent approximately 26.01% of the total

issued share capital of BP, excluding shares held in treasury and shares bought back for

cancellation.

27. BP’s ADSs are sponsored facilities, in which BP entered into a contract with a

depositary bank, JPMorgan. BP’s ADSs are a Level 2 program. As such, BP must file a

registration statement to issue the ADRs and BP is under SEC regulation. In addition, BP is

required to file a Form 20-F annually.

28. In listing its ADRs on the NYSE, BP must meet the NYSE’s listing requirements.

The NYSE requires foreign private issuers, such as BP, who enter into a deposit agreement with

an American depositary for the purpose of sponsoring their ADRs, to have first entered into a

“basic Listing Agreement” with the exchange on which the ADRs will be listed. NYSE Listing

Manual, Sec. 103.04 (“Sponsored American Depositary Receipts or Shares”). Sections 901.02

and 901.03 of the Manual, entitled, respectively, “Listing Agreement for Foreign Private Issuers”

and “Listing Agreement for Depositary of a Foreign Private Issuer,” provide that the issuer (BP)

and the Depositary (JPMorgan) must “have on hand at all times a sufficient supply of” BP

common stock for conversion of ADRs into common stock.

29. As set forth in one leading treatise, “the NYSE has special standards and

procedures for listing . . . ADRs. . .” As a result of these special standards and procedures, “[a]

company is required to list the shares underlying listed ADRs, although the share listing is not

for trading purposes.” Greene, et al., US Regulation of the International Securities and

Derivatives Markets § 2.03[2][b][i] at 2-34 and n. 85 (9th ed. 2009).

30. BP, therefore, was required to enter into a listing agreement with the NYSE



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

covering both ADRs and the ordinary shares.

31. The fact that NYSE requires the issuers of ADRs to register and list the

underlying ordinary shares reflects the reality that the ADRs derive their legal and economic

identity from the ordinary shares. ADRs simply represent ordinary shares that have been placed

in trust with a depositary, thereby qualifying as ADSs.

32. The ADRs are dollar-denominated for trading, pay the same dividends as the

underlying shares (but exchanged into dollars), have the same voting rights and are exchangeable

at the holder’s request for the underlying ordinary shares.

33. The ADRs and the ordinary shares have identical fundamentals. Recognizing that

functional identity, SEC regulations count the ADRs as ordinary shares for reporting and

regulatory purposes. See, e.g., Section II.D.2 of Exchange Act Release No. 34-29226, 1991 SEC

LEXIS 936, at *43 (May 23, 1991) (“A reporting obligation under Section 13(d) is determined

by ownership of the class of deposited securities, including ownership of those securities through

ADRs”).

34. At all relevant times during the Class Period, (i) BP’s ADRs were listed and

actively traded on the NYSE and registered with the SEC, and (ii) BP’s common stock was listed

on the NYSE, registered with the SEC, and traded on the London Stock Exchange and other

exchanges.

V. BACKGROUND

A. The Trans Alaska Pipeline And The Oil Transit Lines

35. When oil was discovered in Prudhoe Bay, a consortium of oil companies

determined that a pipeline offered the best means to transport it from the North Slope (the north

coast of Alaska) to a navigable port in southern Alaska where it could be shipped to refineries in

the continental U.S. In 1977, these companies completed the Trans Alaska Pipeline (“TAPS”)

which stretches 800 miles from the North Slope to the port of Valdez on the State’s southern

shore.

36. Before the oil is pumped into TAPS to be transported to Valdez, it must be



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

transported from each individual well. The oil is moved from about 1,100 active wells, through

flow lines, to one of six processing centers. The processing centers in the WOA are called

gathering centers 1, 2 and 3 (“GC”), while the processing centers in the EOA are called flow

stations 1, 2 and 3 (“FS”). The different terminology simply reflects the different ownership

prior to 2000 of the WOA (BP) and EOA (ARCO).

37. Oil is then transported from the gathering centers through Oil Transit Lines to

pump station 1. Eight miles of Oil Transit Lines are located in the WOA, which transport oil

from two gathering centers (GC-1 and GC-2) in the WOA to pump station 1. There are also

eight miles of Oil Transit Lines in the EOA. These Transit Lines transport oil from three flow

stations (“FS,” FS-1, FS-2 and FS-3) to pump station 1. A third Oil Transit Line carries

partially-processed oil from GC3 in the WOA to FS-3 in the EOA where it joins the transit line

on the Eastern side.

B. Maintenance of Oil Pipelines – “Pigging”

38. A “pig” is the name for a tool, usually shaped like a cylinder, that can be pushed

through the pipeline for cleaning or inspection purposes. There are two types of pigging,

“maintenance” and “smart” pigging.

39. Maintenance pigging consists of inserting a mechanical tool to clean the inside of

a pipeline. Maintenance pigging removes undesirable material, debris (liquid or solid) e.g., wax,

paraffin, scale, sediment and water corrosion cells from accumulating.

40. Smart pigs detect the presence or absence of cracks, corrosion, and pitting within

a pipeline. Smart pigs can quickly process data showing the extent of corrosion along a pipeline

at intervals as small as one-tenth of an inch. Standard operating practices in the oil and gas

industry require a regular pigging program in order to detect corrosion and clear debris. As BP

admits in its own Incident Report for the March 2, 2006 oil spill (defined below), “without

excavation and removal of the outer casing from the pipeline, smart pigging is the only accurate

way to determine the condition of cased or buried pipelines with respect to internal corrosion.”

(Emphasis added unless otherwise noted).



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

VI. SUBSTANTIVE ALLEGATIONS

A. BPXA Knew Years Prior To The Spills That The Failed Oil Transit Lines Were Subject To Highly Corrosive Conditions

41. Based on new documents not alleged in the 2008 complaint, BPXA knew that its

corrosion monitoring system was inadequate and ineffective in light of the specific corrosive

conditions present in the lines that failed in Prudhoe Bay. The main factors that contributed to

the highly corrosive conditions in the WOA and EOA lines included the accumulation of basic

sediment and water (“BS&W”) combined with low pressure. Water and sediment provides an

ideal environment for bacterial growth, insulating the bacteria from the toxicity of the crude oil.

Water has a similar effect. It separates from the crude oil, flows along the bottom, and

accumulates in low areas of the lines where there are elevation changes. Basic sediment also

naturally accumulates on the bottom of the pipelines, especially on low-flow lines like the OTLs

that leaked here. As BPXA’s internal documents show, this combination of factors (BS&W

accumulation and low pressure) created increased risk that bacteria would cause internal

corrosion.

42. The threat of these highly corrosive conditions had been identified as early as

1990 in a memorandum recommending pigging the lines in the EOA:

If the water in the sales line segregates and flows along the bottom of the line, there is the potential for bacterial or underdeposit corrosion, which could result in scattered pitting, or carbonic acid attack, which could lead to a more continuous channeling type of damage. In either case, the most severe damage would be expected at the bottom of the lines. [BPXA00461263].

43. This potential threat of bacterial or underdeposit corrosion identified in the early

1990s became a reality ten years later. In September 2001, David Neill, a corrosion engineer at

BPXA sent an email to the head of the Corrosion group, Richard C. Woollam (“Woollam”),

warning him of significant sediment build-up in the EOA line. Neill had been working on a leak

detection system and after discovering the heavy sediment build up was concerned about

corrosion.

[in] working on installing a leak detection system on the Prudhoe sales oil transmission pipelines….it became evident that significant sediment has built up in the piping. In order to



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

obtain optimum meter accuracy, we need a clean pipe. . . . what would it take to pig these lines and how soon could we schedule it? We are obviously concerned about corrosion, and the possibility of a leak on one of the oil lines. [BPXA01198560].

44. Additional documents (also not alleged in the 2008 complaint) further detail

BPXA’s knowledge that the two OTLs that leaked in 2006 (GC-2–GC-1 and FS-2–FS-1) had a

history of the exact conditions identified years earlier as conducive to corrosion: low velocity

and high BS&W. An August 27, 2006 presentation called “Integrity Assessment of Oil Transit

Lines” included the historical data between 1996 and 2006 for velocity and BS&W in the OTLs.

The one page slide showing a chart of velocities for that period concluded that “GC-2 and FS-2

have exhibited the lowest velocities.”

45. The velocity had decreased steadily from 1996 to 2006 for FS-2 from 1.50 ft/sec

to 0.50 ft/sec. Similarly, GC-2’s velocity ranged from about 1.2 ft/sec to below 1.0 ft/sec.

Velocities of approximately 1 ft/sec were considered “low” by BPXA, as set forth in an April

2006 report entitled, Alaska Transit Pipeline Technology Review. [BPXA00035935]. The

majority of the other OTLs exhibited velocities that were two to three times higher.

[BPXA01630573].

46. The August 2006 presentation also established that GC2 and FS2 had the “most”

variations (technically called “excursions”) from the desired specified level of 0.35% BS&W.

The one page slide showing annual data between 1996 and 2006 for BS&W said, “GC2 and FS2

handle most water and exhibited most excursions from 0.35%.” [BPXA 01630571]. In fact,

GC-2 had experienced a “catastrophic water breakthrough” on February 27, 2005, when

approximately 10,000 gallons of water were released. This catastrophic water breakthrough

occurred shortly before the spike in the corrosion rate was detected in September 2005. [BPXA-

ADEC00576023].

47. In a letter to PHMSA authored by Sandy M. Stash – Vice President of Regulatory

Affairs & Compliance for BPXA – and dated August 31, 2006, BPXA admitted that the low

velocity and BS&W excursions were among the most critical factors that caused the bacterial

corrosion that led to the leaks:



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

the causal factors that appear to most strongly influence thepitting corrosion are flow velocity and inclination of the pipeline, in the presence of water and solids. These factors have created an environment that could lead to Microbiologically Induced Corrosion and/or Under Deposit Corrosion. These factors are not substantially different between the Eastern Operating Area (EOA) and Western Operating Area (WOA). [BPXA01124370].

* * * Both the EOA and WOA have low flow velocities. The two failed oil transit line segments (one in the EOA and one in the WOA) have the lowest velocity of the oil transit lines. BPXA believes this was a significant contributing factor to the corrosion observed. [BPXA01124384]

B. BP Suppressed An Independent Report Showing Ineffective Corrosion Monitoring And Ignored Recommendations to Pig

48. In 1999, BP acquired ARCO, one of its main competitors which also had a

substantial stake in Prudhoe Bay. As a condition imposed by the State of Alaska for the approval

of the acquisition, BPXA entered into a Charter Agreement (the “Charter”) with the State in

which BPXA agreed to a series of “good corporate citizen” initiatives. One of the initiatives was

a “Commitment to Corrosion Monitoring” through a regular annual review of BPXA’s corrosion

related practices for its North Slope pipelines. The review required BPXA to submit an annual

report to the Alaska Department of Environmental Conservation (“ADEC”), the State agency

charged with monitoring BPXA’s corrosion program.

49. In order for ADEC to properly assess the adequacy of BP’s annual report, it hired

Coffman Engineers, Inc. (“Coffman”). Coffman prepared an analysis of BPXA’s report in late

2001 that was extremely damning and critical of BPXA’s corrosion report. Coffman raised the

following prescient questions:

• “Does BPXA pig every non-common carrier pipeline of suitable diameter?”

• “Are there plans to install/reconfigure EOA pipelines for smart pigs?”

• “Are baseline smart pigs performed on newly commissioned lines?”

• “How are the lines selected for smart pigging and what is the recur [sic] frequency of inspection?”



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

50. Nearly five years later, in March and August 2006, BP’s intentional or

deliberately reckless failure to pig and address the very same issues raised by Coffman in 2001

caused massive oil spills, serious damage to the environment, and the shutdown of Prudhoe Bay.

51. Coffman also concluded that the report did not provide sufficient information to

properly and adequately assess BPXA’s corrosion monitoring efforts. In other words, BPXA

pretended to comply with the Charter by providing the report, but the report lacked any real

substance. The Coffman report stated:

While the BPXA report and presentation materials were an initial attempt to meet the expectations outlined in the Commitment to Corrosion Monitoring plan, it does not provide the information necessary for detailed technical analysis.

52. In light of this dearth of data, Coffman concluded as follows:

BPXA stated intent [sic] to ‘report openly, good, bad . . .’ the results of its corrosion management programs. However the reporting style makes it difficult to develop a qualitative understanding of the basis for their corrosion strategy. Program results have been reduced and factored; conclusions are hard to report without making inferences with regard to the underlying reasoning or strategy. The metrics chosen to report results make comparison to industry peers difficult to quantify. No discussion of the underlying program strategy is included other than to say, ‘Our corporate goals are no accidents, no harm to people and no damage to the environment.’

53. When BP received this report it engaged in a heavy-handed campaign to have it

re-written and change its criticism and tone. Tellingly, there is no evidence that BP read

Coffman’s report constructively and sought to address the risks and serious concerns raised by

the report. Instead of working towards pigging the pipelines in Prudhoe Bay, which would have

averted the subsequent disasters of 2006, BP sought to quash the report.

54. Central to this campaign was Woollam. Woollam “took the Fifth” when asked to

testify before Congress in September 2006 in connection with BPXA’s knowledge of corrosion

in its pipelines. See infra ¶ 118.

55. Woollam received the Coffman report on Friday, November 2, 2001, in an email

from Tim Bieri, a professional engineer at Coffman. By the next day, Saturday November 3,

Woollam wrote an internal email, saying, “We are meeting with ADEC on Monday . . . . I am



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

going to speak with Susan Harvey [at ADEC]. . . and determine if we can influence the

content.”

56. The meeting on Monday did not go well for BPXA. As a result, the strategy

“going forward” was to apply heavy political pressure at the top levels of State government.

This strategy was outlined in an email by William H. Colbert (Chief Counsel at BPXA in

Anchorage) to Woollam on November 8, as follows:

I share your concerns about the direction that Coffman/ ADEC seem to be taking . . . .

* * * Given the unacceptable state of affairs in our relationship with ADEC over this issue, I suggest that you do two things: (1) document and summarize your concerns and objections to the Coffman report in a letter to ADEC, and (2) schedule a high level meeting between ADEC Commissioner Brown and Steve Marshall or Ross Klile (or another appropriate ALT member) to air our concerns about the Coffman report and the direction and process being taken by ADEC on this matter.

* * * Another approach, which to me makes sense only if the high level meeting doesn’t produce results, is for me to contact the state Attorney General’s office to see if I might be able to enlist their assistance in persuading ADEC that it is in their best interest to cooperate and work with BP.

57. As a result of BPXA’s efforts, the Coffman report was re-written and all the

damning language deleted. The revisions to the report changed its conclusions completely, and

can be best described as an exercise in “Orwellian speak.” For example,

• all the questions posed by Coffman about pigging (which if BP had followed would have prevented the 2006 spills) were replaced by an innocuous statement that said, “If maintenance pigging is a part of the corrosion mitigation effort, then discussing [in BP’s report] the pigging intervals and program details for various services would be useful;” and

• the paragraph stating that BP’s report did not provide the information necessary for adequate technical analysis was replaced with the following sentence: “The BPXA report and presentation materials were a positive step towards meeting the expectations outlined in the Commitment to Corrosion Monitoring plan.”



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

C. BP’s Board Of Directors Knew Of TheWidespread Corrosion At Prudhoe Bay In 2004

58. BP’s Board of Directors had been specifically warned about severe corrosion

problems at Prudhoe Bay in May of 2004 – almost two years before the spill. This was revealed

on August 8, 2006, in Financial Times article titled, “BP Given Earlier Warning Of Prudhoe

Corrosion” (the “August 8 FT Article”).

BP’s board and London-based executives were informed of widespread corrosion at the UK oil giant’s Alaska field two years before the company was forced to shut it this week, citing “unexpectedly severe corrosion.”

On May 22, 2004, Chuck Hamel, an advocate for BP workers in Alaska, took the charges directly to Dr. Walter E. Massey, chairman of the environment committee of BP’s non-executive board of directors.

In the letter, Mr. Hamel told Dr. Massey that in the previous four years BP employees and contract workers had brought to him concerns about safety, health and threats to the environment at Prudhoe Bay, Alaska.

“They seek to see the corrosion problem addressed and corrective action undertaken without further delay and before any of their colleagues at Prudhoe are harmed,” he wrote in the letter, a copy of which was given to the Financial Times at the time.

Mr. Hamel warned Dr. Massey that, as a board member, he owed it to shareholders to investigate. He said he would facilitate interviews with the BP engineers and corrosion experts if his committee provided assurances they would not suffer retaliation.

On July 27, 2004, Dr. Massey wrote to Mr. Hamel urging him to provide BP management “sufficient specificity” but without offering the requested protection.

59. A similar story ran on MSNBC.com on August 9, 2006, titled, “BP Admits

Knowing of Corrosion Problems.”

BP now admits that senior company officials were warned three years ago about serious corrosion problems in the pipeline being shut down this week.

The warnings were laid out in correspondence obtained by NBC News, between Chuck Hamel, an advocate for oil workers, and senior BP officials.

Hamel writes that BP workers had come to him predicting a “major catastrophic event” and warning that “cost cutting” had caused “serious corrosion to flow lines and systems.”



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

“They were cheating in what’s required of them in normal business practice in an oil field to save money, to cut corners,” Hamel says.

D. BPXA Knew In September 2005 That The Corrosion Level In The Pipeline That Failed In March 2006 Was “High”

60. In addition to the May 2004 letter sent by Mr. Hamel to Dr. Massey, BPXA had

additional evidence in September 2005 that the OTLs were heavily corroded and, more

importantly, that corrosion had spiked to the “highest” level in six years in the OT-21 line - the

very same transit line that failed in March 2006. This additional evidence is set forth in the

Incident Report concerning the March 2006 Spill prepared by BP for ADEC, which was entitled:

GC-2 Transit Line Spill Incident Investigation Report (the “Incident Report”).

61. The Incident Report shows that the maximum rate of corrosion activity had

increased from 3 mills (thousandths of an inch) per year (“MPY”) in 2004, to 32 MPY in 2005, a

ten-fold increase:

Year Max Corrosion Rate (MPY)1999 132000 N/A 2001 02002 212003 02004 32005 32

62. The same report also showed that the number of locations with corrosion activity

in OT-21 increased to 7 in 2005, from 1 in 2004. There had never been more than 2 locations

showing corrosion in any year since 1999, and the cumulative number of areas showing

corrosion between 1999 and 2004 was only 4. Yet, in 2005 alone, this number had jumped to 7.

63. Accordingly, the Incident Report concluded, “[c]learly though something began

to change in 2005 when the data from seven locations showed an increase and the corrosion

activity was the highest it had been over the past six years at 32 MPY” in the OT-21 line.

64. Indeed, the same report left no doubt that the corrosion rate found in 2005 of 32

MPY was “high.” The report showed the rate of corrosion for various locations between 1998

and 2005 and classified the corrosion rate based on three different levels: (i) MPY = 0; (ii) MPY



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

<= 20; (iii) MPY > 30. The corrosion rate for OT-21 in 2005 at 32 MPY therefore fell squarely

within the highest classification ascribed by BPXA.

65. Additional documents, newly alleged here, not only establish that 32 MPY

constituted a “high” level of corrosion, but also that it was not “low and manageable.” In

preparation for BP’s Congressional testimony in 2006, BP’s senior executives were provided

with a detailed memorandum outlining questions provided in advance and suggested responses.

This September 6, 2006 memorandum admitted that the corrosion rate prior to September 2005

was “low and manageable,” but not the corrosion rate of 32 MPY detected in the fall of 2005.

Q. Who made the decision not to pig? (the EOA)

A. When BP took over operation of the EOA, it included the oil transit line in its routine direct assessment program for the WOA oil transit lines. Inspections prior to the fall of 2005 showed low and manageable corrosion rates in all oil transit lines, so pigging was not directed. Upon observing the higher corrosion rates on the WOA in 2005, pigging was ordered by BPXA Corrosion Inspection and Chemicals for the summer of 2006. [BPXA01620572].

66. Similarly, an April 2005 Internal Audit report on BPXA’s Corrosion Management

System, newly alleged here, also established that 32 MPY was a high corrosion rate and

dramatically higher than the accepted norm. As part of the section on risk assessment, the report

recommended a thorough review of the corrosion management strategy which had not been

updated since 1999. It then added, “[t]he review should include a more accurate definition of

field life and its criticality and risk associated with achieving the current operating criterion of

< 2 mpy internal corrosion rate, noting that ~100% of production flowlines [not the OTLs], for

example, are now exhibiting corrosion rates of ~0.4 mpy.” [BPXA01643668].

67. Finally, Lead Plaintiffs attach the expert report of Lead Plaintiffs’ newly retained

expert Dr. John S. Smart III. Dr. Smart has nearly 40 years of experience as a corrosion

engineer, metallurgist and operations engineer with The International Nickel Company, Amoco

Corporation, and as a corrosion consultant. Dr. Smart received his B.E. in Chemical Engineering

from Yale University in 1963, and his Ph.D. in Materials Science from Northwestern University

in 1968. A copy of Dr. Smart’s curriculum vitae is attached to his opinion (Exhibit 1 hereto).



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

68. Dr. Smart opined that a corrosion rate of 32 MPY was “high,” that BPXA

“seriously mismanaged” the corrosion, and that the corrosion was “not manageable” absent

maintenance pigging. (Exhibit 1 at 3). BPXA did not maintenance pig the OTLs at the time.

Dr. Smart’s opinion was based on the following findings:

(a) the on-set of corrosion due to water stratification in the pipeline was never

considered by BPXA as part of the corrosion analysis;

(b) the corrosion inhibitor program in the field did not control the corrosion in

the pipeline;

(c) corrosion monitoring depended on spot checks using UT testing where the

engineers could get to it, and did not focus on the most likely internal corrosion locations;

(d) in-line inspection using instrumented pigs, a technology which was well

developed at the time of the leaks, and which could have detected the corrosion over 100% of the

pipe wall, were not run. (Exhibit 1 at 3).

69. Dr. Smart further opined that a tolerable corrosion rate for the OT-21 line was

limited to “a few mils per year.” Id. This is consistent with BPXA’s internal documents

establishing an operating criterion of less than 2 MPY.

70. The clear conclusion from these documents and expert opinion is that the

corrosion rate in the OT-21 line (i) had changed in September 2005 from “low and manageable”

to high (indeed, to the highest level in six years), and (ii) was not manageable without

maintenance pigging.

E. BPXA Failed To Pig Despite Knowing Of Water And Sediment Buildup And Increased Corrosion, And Despite A Consensus And Internal Documents Establishing That Pigging Must Be Part Of Any “Sound” or “World Class” Corrosion Monitoring System

71. Despite knowing that the OTLs were subject to highly corrosive conditions due to

water and sediment buildup, and despite knowing that the rate of internal corrosion had spiked

ten-fold from 3 to 32 MPY in September 2005, Defendants failed to use the only corrosion

monitoring method that would have detected internal corrosion throughout the length of the lines

– a smart pig. Instead, corrosion monitoring was limited to two other methods that BPXA’s



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

internal documents admit would not have detected the internal corrosion that caused the oil spills

in 2006: ultrasonic thickness testing and weight-loss coupons.

72. Ultrasonic thickness testing, or UT, uses sound waves to measure the thickness of

materials and detect any anomalies. Weight-loss coupons consist of metal samples that are

exposed to the internal environment. The samples are weighed pre- and post-exposure,

providing a measure of metal loss.

73. Both of these inspection techniques were admittedly inadequate to monitor

internal corrosion, especially in the below-ground caribou crossings where the March leak

ultimately occurred. (A caribou crossing refers to the portion of the pipeline that dips into the

ground to enable caribou to cross). The shortcomings of each inspection technique are set forth

in BPXA’s April 14, 2006 Incident Investigation Report.

Buried caribou and road crossings are not capable, without excavation and sleeve removal, of being inspected via Ultrasonic Thickness (UT) technology.

A guided wave UT was recently conducted at this particular caribou crossing and another was just conducted after the incident. Neither of these inspections, however, shows evidence of internal corrosion on the pipeline. This is largely because the guided wave UT method mainly detects large volumetric metal loss. As a result, by design it is not as sensitive to internal pitting as it would be to large amounts of external corrosion….

The coupon data does not show any evidence of increasing corrosion trend. This may be explained by the fact that the coupons are in the flow stream and the corrosion damage appears to be primarily located on the bottom of the line on certain uphill runs.

74. In light of the ineffectiveness of the corrosion monitoring techniques used by

BPXA, the Incident Report admitted that the only way for BPXA to have detected internal

corrosion at the caribou crossings was through smart pigging:

Without excavation and removal of the outer casing from the pipeline, smart pigging is the only accurate way to determine the condition of the cased or buried pipelines with respect to internal corrosion.

With the exception of smart pig runs, there isn’t a way to directly monitor internal corrosion inside of cased pipe (road and caribou crossings) without having to excavate the crossing and remove the outer casing from the pipe.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

75. Additional documents further evidence that any “sound” or “world class”

corrosion monitoring system had to include pigging. For example, Oregon Representative Greg

Walden made this point at the Congressional hearings on September 7, 2006, stating that

“[e]xperts to a person have explained pig runs as an essential element of any sound corrosion

control program.”

76. The Department of Transportation concurred. A letter to Representative John D.

Dingell dated June 5, 2006 by Maria Cino, the Deputy Secretary of Transportation, said: “The

DOT has not received a reasonable explanation why BP has not scraper-pigged these lines over

an approximate 14-year period. In our opinion, based on current information, this length of time

does not represent sound management practices for internal corrosion control.”

77. Even Robert Malone, then Chairman and President of BP America, Inc. agreed,

stating on August 7, 2006 at a press conference that, “as someone who was President of Alyeska

pipeline for over four years, there was clearly a world class corrosion program at Alyeska with

pigging and smart pigging on [a] periodic basis upon expertise from our corrosion expert.”

F. The March 2, 2006 Oil Spill

78. On March 2, 2006, BP discovered a crude oil spill in the Oil Transit Line

operating between GC-1 and GC-2, commonly referred to as the OT-21 line. That line is

approximately 16,500 feet long, or 3.1 miles. A GC-2 well-pad operator had driven the OT-21

line segment early the morning of March 2 and smelled the oil. The operator notified the lead

operator immediately. Despite a supposedly “world class” leak detection system, the leak was

discovered by smell.

79. Subsequent analysis revealed that the leak was the result of a hole about 0.25

inches in diameter, at the bottom of the steel pipe, inside a culvert, and underneath a caribou

crossing. The hole was caused by internal corrosion.

80. The estimated size of the spill was approximately 4,800 barrels, or about 200,000

gallons. Based on the amount of the spill and the size of the hole, the Incident Report concluded

that the leak remained undetected for at least 5 days, and probably much longer.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

G. Defendants Intentionally, or With Deliberate Recklessness, Ignored the Government’s Corrective Action Order Issued After The March 2 Oil Spill, Leading To The August Shutdown

1. The March 15, 2006 Corrective Action Order

(a) The CAO Raised Serious Concerns

81. On March 15, 2006, PHMSA issued a Corrective Action Order (“CAO”) to

BPXA, thereby asserting federal jurisdiction and oversight over the oil transit lines. These lines

were generally not required to be overseen by a federal agency in light of their low oil pressure

and limited length. PHMSA justified the issuance of the CAO as necessary “to protect the

public, property, and the environment from potential hazards.” It was addressed to Defendant

Johnson.

82. The CAO made a series of preliminary findings, which, altogether, raised

extremely serious concerns about the lack of maintenance of the OTLs:

• The cause of the leak discovered on March 2 was “internal corrosion,” and there was evidence of bacterial corrosion (increased hydrogen sulfide and nitric acid in the crude oil) and increased water content.

• Six additional “anomalies” showing internal corrosion had been subsequently identified in the transit line. One “anomaly” showed corrosion of 90% of the wall thickness, with only 0.04 inches of the wall remaining.

• The WOA transit line (the one that caused the spill) had not been pigged since 1998 and there were no regular smart pigging (inspection) or regular pigging (maintenance) programs for any of the transit lines.

• The leak detection system was not effective in recognizing and identifying the failure.

83. In light of these findings, PHMSA issued the CAO immediately, without

providing the usual opportunity for a notice and a hearing.

After considering the age of the pipes, the hazardousness of the product the pipelines transport, the large spill volume, the ineffectiveness of the leak detection system to identify the leak, the similarity of the []EOA . . . to the pipeline that failed, and the proximity of the pipelines to wildlife areas or other possible sensitive areas, I find that the continued operation of [BPXA’s] WOA, EOA, and Lisburne hazardous liquid pipelines without corrective measures will be hazardous to life, property, and the environment. Moreover, failure to expeditiously issue this Order



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

requiring immediate corrective action would likely result in serious harm to life, property, or the environment.

Accordingly, this Corrective Action Order mandating immediate corrective action is issued without prior notice and opportunity for a hearing. The terms and conditions of this Order are effective upon receipt.

84. The CAO listed specific “Required Corrective Actions,” including:

• Item 3. Smart pigging the WOA within 3 months of placing that line back in service.

• Item 4. Developing and submitting a plan for running maintenance pigs (cleaning pigs) in all transit lines on a regular basis. Until that plan is approved and implemented, BPXA was ordered to run maintenance pigs on the EOA and WOA on a weekly basis.

• Item 6. Developing and submitting for PHMSA approval an internal corrosion management plan to reduce internal corrosion in the OTLs. The plan had to address the use of corrosion inhibitors, emulsion breakers, and mechanisms to reduce water and solid particles, and allow for monitoring sludge extracted from the pipelines.

• Item 7. Inspecting the EOA and Lisburne transit lines using a smart pig “within 3 months of receipt of this Order,” in other words, before June 15.

85. BP and BPXA, intentionally or with deliberate recklessness, violated the CAO by

not smart pigging the EOA transit line until July 22, 2006, 37 days after the mandatory deadline.

(b) The WOA and EOA Pipelines Had Similar Characteristics and Corrosive Conditions

86. The CAO also specifically linked the failed line in the WOA with the EOA line.

The CAO expressed concern that in light of the similarities of the pipes and environmental

conditions the EOA could also fail:

The PBWOA [WOA line] is one of three similar low-stress pipelines operated by Respondent that feed into PS-1. The other two pipelines are the Prudhoe Bay East Operating Area (PBEOA) pipeline and the Lisburne pipeline. All three pipelines were constructed around the same time, operate in similar environmental conditions, transport the same quality crude oil that contributed to the cause of the internal corrosion in PBWOA, and are operated and maintained in a similar manner by Respondent.

87. In light of the similarity of the operating conditions and maintenance of the WOA



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

and EOA lines, PHMSA determined that the spill in the WOA line required emergency action in

the EOA line also:

After considering the age of the pipes, the hazardousness of the product the pipelines transport,…the similarity of the [EOA] . . . to the pipeline that failed ,... I find that the continued operation of [BPXA’s] WOA, EOA, and Lisburne hazardous liquid pipelines without corrective measures will be hazardous to life, property, and the environment.

88. The CAO thus left no doubt that the WOA transit line which suffered the March 2

spill was “similar” to the EOA lines, and that the environmental and operating conditions of

both lines were also similar. Accordingly, the CAO specifically ordered inspection and

maintenance of the EOA lines for this reason.

89. Not only did PHMSA consider that the WOA and EOA were similar and

exhibited similar operating and environmental conditions, but so did BP. The September 6, 2006

memorandum preparing BP’s witness for their Congressional testimony admitted that the EOA

and WOA lines were subject to similar conditions to be treated the same:

Q. How could BP have been confident of its (EOA) condition without a more extensive testing regime?

A. There is a certain amount of similarity between the EOA and WOA oil transit pipelines. Because of these similarities it was believed the pipelines also had similar conditions. The WOA oil transit pipeline had data from routine inspection, 1998 in-line inspection data, and corrosion monitoring (weight loss coupon) data. [BPXA0162571].

90. In other words, BP’s operation and maintenance of the EOA and WOA lines was

premised on the assumption that (i) the lines were similar and subject to similar conditions, and

(ii) testing results from the WOA line were equally applicable to the EOA line.

91. Defendant Johnson, as BPXA’s spokesperson, however, told the public exactly

the opposite – that the pipelines were not similar and that corrosion and leaks in one OTL were

not indicative of the condition in the other. On March 15, 2006, the Associated Press reported

that “[s]imilar problems have not been found in other lines downstream and elsewhere in

Prudhoe Bay, and Johnson said it appears the highly corrosive conditions were unique to



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

that line.” Then, on May 14, 2006 Petroleum News reported that according to Defendant

Johnson, “We’ve looked at all of the oil transit lines . . . none other has the same combination

of factors . . . . Going forward we’ll pig out oil transit lines on a regular basis.”

92. The clear import of Defendant Johnson’s statements was that the OT-21 line was

an exception. This was false. These statements falsely reassured the market that the March 2 oil

spill would not be repeated and, as a result, that the continued flow of oil from Prudhoe Bay was

not in critical danger.

2. BP’s Board Was Informed That There WasA Risk of Additional Leaks In May 2006

93. Based on new documents not alleged in the 2008 complaint, on or about May 5,

2006, the BP Board was given an update about the March spill, entitled “Alaska Update,” which

is newly alleged. It was prepared by David K. Peattie (“Peattie”) – BP’s Vice President for

Exploration and Production. In an email from Peattie’s executive assistant (Tony Brock) to

Marshall, Brock confirmed that Peattie intended to give the update to Defendant Browne,

Hayward, and Andrew Inglis who was the Deputy Chief Executive for Exploration and

Production. [BPXA00955792].

94. A subsection called “Current status – Where are we now?” said:

Inspections have indicated that the corrosion which led to the leak may not be an isolated case. Further smart pig inspections andmaintenance pig runs are required to completely verify that all pipelines meet integrity standards. [BPXA00955795].

95. Accordingly, the Board (or at a minimum key Directors including the CEO) had

been warned that there was a risk of additional leaks, and that smart pig inspections and

maintenance pig runs were essential to prevent such leaks.

3. Hayward Knew That BPXA Had Violated The CAO

96. Also based on new documents not alleged in the 2008 complaint, on June 12,

2006, Hayward requested a briefing memorandum concerning the response to the March spill.

(At the time Hayward was a BP Director and Chief Executive for Exploration & Production and

not yet CEO). The request arose after a lunch meeting between Hayward and Defendant



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

Browne, and in preparation for a scheduled meeting on June 12, 2006 between Hayward and the

Chairman and CEO of ConocoPhillips, James J. Mulva.

97. Involved in the preparation of this memorandum was Defendant Johnson, who

proposed an outline that included the following topics: “Oil Transit Lines – Pigging; DOT

[Department of Transportation]; OT-21 replacement.” [BPXA00451340].

98. The briefing document, ultimately titled “Alaska 2006 IM [Integrity

Management] Forward Plan,” explained the status of BPXA’s lack of compliance with the CAO.

It specifically stated that the deadline to pig the OTLs was June 15 and that the EOA had not

been pigged.

The Alaska [Business Unit], led by Maureen Johnson, has had three meetings with the DoT in Washington, DC in April, May & June to apprise them of the progress being made to meet the CAO compliance target date of June 15th. One of the main points of the CAO was the immediate pigging of all oil transit lines, followed by smart pig runs to assess line integrity . . . . [C]oncerns by Alyeska Service Co. about non-routine pigging solids associated with the EOA oil transit lines have slowed progress down on this aspect of compliance to the CAO. Alternate options are currently being worked to take EOA pigging returns to other tankage, but these solutions are several months out in execution once approved . . . . Efforts are underway with the DoT to either amend or extend the compliance order to address these issues. [BPXA01020754; BPXA01020755].

99. Thus, Hayward knew that BPXA had not complied with the CAO.

4. Amendment No. 1 To The CAO

100. On July 20, 2006, PHMSA issued Amendment No. 1 to the CAO. Amendment

No. 1 further contradicted Johnson’s false and misleading statements to the press. It also

displayed alarm and consternation that BP had not yet smart pigged the transit lines and did not

know the extent of the existing risk – more than four months after the March 2 Oil Spill.

101. As a result, Amendment No. 1 issued a stern warning to the Company: “BP has

failed to meet its continuing responsibility to pursue all available options for meeting the

requirements of Items 3 [smart pigging WOA], 4 [plan for maintenance pigging of all

transit lines], and 7 [smart pigging EOA] of the March 15, 2006 CAO.” BP and BPXA had

intentionally, or with deliberate recklessness, violated the CAO.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

102. Amendment No. 1 further explained the immediate risk posed by BP’s inaction

with similar language previously included in the CAO.

[A]fter considering the circumstances surrounding the failure discovered on March 2, 2006, the hazardous nature of the liquids remaining in OT-21 [the segment of the transit line that caused the March 2 spill], the immediate proximity of the pipeline to environmentally sensitive areas, the extensive corrosion and wall thinning found in OT-21, the potential for additional corrosion and wall thinning due to current idle conditions, the presence of water, and the safety and environmental threats posed by those conditions, I find that failure to expeditiously issue this Amendment would result in likely serious harm to property and the environment.

Accordingly, this Amendment ordering immediate corrective action is issued without prior notice and opportunity for a hearing. The terms and conditions of this Amendment are effective upon receipt.

H. The August 7, 2006 Shutdown of Prudhoe Bay

103. On August 5 and 6, 2006, BPXA discovered that on the other side of Prudhoe Bay

from where the March 2 Oil Spill had occurred, in the EOA, there had been a new spill of

approximately 1,000 gallons of oil. BP also discovered that the EOA transit lines were riddled

with small holes and areas of corrosion – approximately 187 corrosion spots. Portions of the

EOA transit line, specifically the segment between FS-1 and FS-2, were in much worse shape

than the OT-21 segment in the WOA that had caused the March spill. This new spill and the

discovery of extensive corrosion on the EOA transit line led to the shutdown of Prudhoe Bay

on August 6.

104. On Sunday, August 6, 2006, at 7:30 p.m., BP publicly announced the shut down

of oil production at Prudhoe Bay due to the purportedly surprising discovery of unexpected

corrosion and a new oil spill. The press release stated:

BP to Shutdown Prudhoe Bay Oil Field

Company acts in response to spill, unexpected corrosion

ANCHORAGE -- BP Exploration Alaska, Inc. has begun anorderly and phased shutdown of the Prudhoe Bay oil field following the discovery of unexpectedly severe corrosion and a small spill from a Prudhoe Bay oil transit line. Shutting down the field will take days to complete. Over time, these actions will reduce Alaska North Slope oil production by an estimated 400,000



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

barrels per day.

The decision follows the receipt on Friday August 4 of data from a smart pig run completed in late July. Analysis of the data revealed 16 anomalies in 12 locations in an oil transit line on the [EOA].

In response to the inspection data, BP conducted follow up inspections of anomalies where corrosion-related wall thinning appeared to exceed BP criteria for continued operation. It was during these follow up inspections that BP personnel discovered a leak and small spill estimated at 4 to 5 barrels.

* * *BP America Chairman and President Bob Malone [said], “the discovery of this leak and the unexpected results of this most recent smart pig run have called into question the condition of the oil transit lines at Prudhoe Bay.”

105. Given that BP knew and had been warned that the pipelines at Prudhoe Bay were

severely corroded, MSNBC.com published an article on August 9 with the headline, “Was the

Pipeline Problem Preventable?” The article questioned BP’s claim that the corrosion was

unexpected.

When British Petroleum (BP) shut down a vital oil pipeline, the company blamed “unexpectedly severe corrosion” in transit pipes. Yet only five months ago, BP’s aging pipeline created the largest-ever oil spill on Alaska’s North Slope.

Federal regulators blamed the spill on “internal corrosion” and said in some areas the walls and pipes were so corroded they were almost paper-thin.

So critics and industry experts say the latest problem was hardly a surprise.

“I think this was predictable and preventable,” says Phil Flynn, an energy analyst with Alaron Trading Corp.

In fact, allegations about BP’s maintenance practices have been so persistent that a criminal investigation now is under way into whether BP has for years deliberately shortchanged maintenance and falsified records to cover it up.

* * * Tuesday [August 8], in an interview with NBC News, a federal official in charge of pipeline safety charged that BP has been doing inadequate maintenance for 15 years.

“Frankly, we would have expected a higher level of care from a company like BP on lines like this,” says Thomas J. Barrett with the Department of Transportation Office of Pipeline Safety. “What disappointed me was their failure to maintain these



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

lines to an accepted industry level of care.”

106. The extent to which BP knowingly, or with deliberate recklessness, failed to

maintain the pipelines was further laid bare in more detail in another Financial Times article by

Sheila McNulty on August 14, 2006:

[The oil spills could] have been avoided if BP had used the state-of-the-art, high technology pigging cleaning and corrosion-testing equipment on all of the 1,500 miles of pipeline that winds its way, several feet above ground, around the more than 200,000-acre field just seven miles from the Arctic Ocean.

The UK oil giant has regularly used pigging equipment on its water-injection lines, as well as its three-flow lines, which hold oil, gas and water.

But it says it did not deem them necessary on the oil transit lines that carry only crude oil because BP did not consider them at risk for the microbial corrosion it believes weakened the pipelines.

* * * …BP’s critics are unwilling to let the company off with a mea culpa. Whistleblowers have for years issued warnings about ineffective corrosion monitoring through Chuck Hamel, a retired oil industry executive who has become their advocate.

* * * BP had not pigged the pipeline with the leak still being cleaned - the eastern transit line - since 1992. It had not pigged the one on the western side of the field since 1998.

In contrast, Alyeska, which runs the trans-Alaska pipeline that carries BP's oil 800 miles across Alaska to Valdez on the Pacific, where it is put on tankers, pigs its line every two weeks.

107. The same article also showed that industry experts did not believe BP’s excuses

that it had no reason to suspect the serious corrosion of its pipelines and that it was reasonable

not to have pigged the lines.

[I]ndustry experts argue that for BP to say it did not suspect microbial bacteria in its transit lines is just not credible.Microbiologic influenced corrosion, or MIC as it is known in the industry, has been something companies have guarded against for decades.

“Any prudent operator is going to be sure it does not have MIC and is going to periodically run cleaning pigs to sweep out colonies if they do form,” says Rick Kuprewicz, president of Accufact, a pipeline energy consulting firm. “MIC is not something that space science invented last year.”



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

He notes that the oil transit lines are like the main arterials on an oilfield: “If you’re not looking at this stuff, what’s going on here?”

BP says it was using other corrosion-detecting tools, such as sticking metal coupons into the pipeline and watching them for corrosion, as well as putting in corrosion-inhibiting chemicals and then using ultrasonic technology to listen for weak spots. But each of these has its weakness.

The coupons and the ultrasonic technology only reveal the state of the pipeline in the exact area where they are placed, and the chemicals never reach the sides of the pipeline if they are too filled with sludge, as in this case. Maintenance pigging, which actually scrapes the sides of the entire pipeline with metal bristles, is considered the best way to get rid of corrosion-causing agents.

* * * Mr. Kuprewicz is... surprised a company of BP’s stature - one of the biggest in the world - did not routinely pig its oil transit lines. “Most companies understand that federal regulations are a minimum,” he says. “This is extremely embarrassing to the oil industry.”

I. Amendment No. 2 To The CAO

108. As a result of the shutdown on August 6, PHMSA issued Amendment No. 2 to the

CAO on August 10, 2006. The preliminary findings documented that BPXA knowingly or with

deliberate recklessness failed to follow the March 15 CAO. BPXA had not smart pigged the

FS2-FS1 segment of the EOA until July 22, 2006. This was 37 days after the mandatory

deadline imposed by the CAO.

109. The results of the smart pig data of the FS-2 - FS-1 segment set forth in

Amendment No. 2 showed cripling corrosion. There were sixteen different corroded spots with

wall loss exceeding 70 percent, including two over 80 percent. Each of the sixteen spots was

approximately 1.5 by 1.5 inches in size and was located in the bottom quadrant of the pipe

(between the 5:45 and 6:45 positions).

110. Alarmed by the results, BPXA performed direct visual inspections of the 16

locations identified by the smart pig. What it found was horrifying.

[BPXA first] discovered a location where crude oil apparently had leaked through the pipe wall and onto the insulation material. . . . Later in the morning of August 6, 2006, according to BP, BP



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

personnel discovered crude oil leaking from a different location on the FS2-FS1 segment of the EOA pipeline. According to BP, field inspection of the leak site revealed multiple holes in the pipe wall at a single location, contributing to an estimated spill of approximately five barrels of processed crude oil.

Since August 6, 2006, BP reportedly has discovered pinhole leaks on at least four additional locations on the FS2-FS1 segment of the EOA pipeline.

111. Within three days, on August 9, BPXA further informed PHMSA that it had

determined that the FS-2 – FS-1 segment was so corroded, and in such poor condition, that it

would not fix it. Instead, BPXA decided to build a bypass line. Similarly, the OT-21 segment

on the WOA was also in such a state of disrepair that BPXA would also permanently bypass it.

112. In light of these facts, PHMSA had no choice but to issue Amendment No. 2. As

set forth in the Amendment:

After considering the circumstances surrounding the failures discovered on August 6 and March 2, 2006, the number and severity of anomalies discovered on the EOA line, the immediate proximity of the pipeline to environmentally sensitive areas, and the safety and environmental threats posed by serious internal corrosion of the EOA line, I find that failure to expeditiously issue this amendment would result in likely serious harm to life, property and the environment.

113. Amendment No. 2 included even more stringent directives and corrective actions.

Pursuant to Item 22, BPXA was to “begin four times daily visual and handheld infrared surveys

via ground patrol of the entire length of the EOA, Lisburne and WOA pipelines . . . . [and] shall

report the results of the surveys to the [PHMSA] on a weekly basis, provided that any leaks or

threats to pipeline integrity must be reported immediately.”

114. PHMSA clearly had been dissatisfied with the level of cooperation provided by

BPXA since March 2006, and so it issued specific corrective actions mandating periodic

reporting requirements with extremely tight deadlines.

• Within 48 hours of the receipt of this Amendment No. 2, BP shall provide [PHMSA] with all data and risk analyses not previously provided by BP, concerning the current condition of the WOA pipeline.

• As repairs are made, BP shall submit monthly reports to [PHMSA] documenting each repair made (including photographs) with respect to each anomaly.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

• Within 30 days of the receipt of this Amendment No. 2, BP shall submit a report to [PHMSA], detailing its proposed actions and plans for replacing, abandoning, and/or restoring operation of the FS2-FS1 and FS1-Skid 50 segments of EOA.

115. These regular reporting requirements mandated by Amendment No. 2 had been

absent from the CAO issued in March. The CAO had primarily ordered BPXA to take remedial

measures, such as pigging, smart pigging, and inspecting, monitoring, and repairing the

pipelines. It did not set forth any deadlines or establish any oversight. Five months later, in

August, after BPXA had effectively ignored PHMSA’s orders and directives, PHMSA took on a

much more aggressive oversight role. The more stringent oversight put in place by PHMSA is

further evidence that BPXA had dragged its feet and, intentionally, or with deliberate

recklessness, violated the CAO. A month after Amendment No. 2, PHMSA officials testified

before Congress to this effect.

J. Congressional Hearings And Investigation

116. The magnitude of the oil spill on March 2 and the shutdown of Prudhoe Bay

starting on August 6, 2006 led to public outcry and calls for a deep and thorough investigation of

BP’s conduct. Congress was outraged. On August 11, 2006, United States Representative Joe

Barton, Chairman of the Energy and Commerce Committee, wrote a letter to then-Chief

Executive of BP John Browne, suggesting that BP had misled Congress:

BP has repeatedly assured the Committee that the condition of the pipeline that failed in March was an anomaly, and that BP’s corrosion control program was an effective means to monitor and maintain pipelines and infrastructure on Alaska’s North Slope.

News that BP production of roughly 400,000 barrels per day of crude oil at Prudhoe Bay has been shut down due to excessive corrosion of its oil transit pipelines contradicts everything the Committee has been told. The fact that BP’s consistent assurances were not well grounded is troubling and requires further examination..

117. On September 7, 2006, several BP executives were called to testify about the

shutdown of Prudhoe Bay at a hearing before the Subcommittee on Oversight and Investigations

of the United States House of Representatives Committee on Energy and Commerce (“House

Energy Committee”).



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

1. The Head Of The Corrosion Division Takes The Fifth

118. Richard C. Woollam, the former leader of the CIC program at BPXA, refused to

testify under oath and invoked the Fifth Amendment:

MR. WALDEN - Mr. Woollam, you were formerly in charge of the Corrosion Inspection and Chemicals Group at BP Exploration Alaska, Incorporated. You were the decision-making manager and engineer responsible for all operations related to corrosion control and monitoring of the pipelines operated by BP at Prudhoe Bay. The subcommittee has learned from several sources that numerous red flags were raised about the integrity of the Prudhoe Bay pipelines while you were in charge of the CIC group including the 2000 final draft Coffman report. Yet in 2002 you initiated and implemented a plan to reduce the manpower of a key pipeline corrosion monitoring team by 25 percent. So my question, Mr. Woollam, when did you become aware of the pipeline integrity problems faced by the Prudhoe Bay Transmission lines including concerns about accelerated localized corrosion, microbial corrosion and that the failure to send maintenance pigs or smart pigs down the transmission lines was placing those pipelines at high risk of failure.

MR. WOOLLAM. Mr. Chairman, based upon the advice of counsel, I respectfully will not answer questions based upon my right under the Fifth Amendment of the U.S. Constitution.

119. Having invoked the Fifth Amendment of the U.S. Constitution, Lead Plaintiffs

and the Class are entitled to an adverse inference of scienter with respect to Defendants’ conduct

here.

2. PHMSA Testified That BP’s Conduct Was Mystifying and Violated The Industry Standard of Care

120. Also at the hearing, PHMSA Administrator Barrett testified regarding BPXA’s

failure to properly maintain its pipelines:

[BPXA’s] management of the lines in the years leading up to the March incident and their initial response to our orders was disappointing. Frankly, we do not understand why BP did not more aggressively address the corrosion problems that led to these leaks. Given the multiple risk factors for corrosion in the Prudhoe Bay environment and the low velocities on these lines, it is mystifying that BP did not run cleaning pigs regularly on these transit lines. Most pipeline operators demonstrate a higher standard of care than this regardless of whether they are federally regulated or not.

Until recently, [BPXA] has not moved as swiftly as we would have expected to comply with key requirements of our orders - namely, the requirements to clean and smart pig its low stress lines.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

* * *It was as a result of the pigging that we ordered that BP discovered the wall loss and the leaks on a line segment in the eastern operating area that led to the production shutdown on 6 August.

* * *On July 22, 2006, 37 days after the deadline established in our March order, [BPXA] performed the smart pigging ordered by PHMSA.

* * *When that pig run came back, about 16 spots with significant wall loss, but if you looked a little broader, you would see, I think the number I saw was about 187 spots with wall loss approaching 50 percent. This was not an isolated couple of spots. This was a number of spots where you had a substantial problem, and frankly [BPXA] had no explanation.

Frankly, the problems we see on these lines are not replicated elsewhere, even in Prudhoe Bay or elsewhere in the industry . . . . typically up on the North Slope and generally in the industry, you would see maintenance pigs every couple of weeks, certainly every couple of months, but not never on lines of this type.

3. The President of Alyeska Pipelines Testified That He Was Unaware Of Any Oil Pipeline Comparable To The EOA and WOA Lines That Were Not Pigged

121. Kevin Hostler, President and CEO of Alyeska Pipeline Service, also testified

about BPXA’s deviation from industry-wide pigging practices. His testimony discussed the

importance of pigging low-stress lines, like the ones that leaked at Prudhoe Bay, where oil

moves slowly, giving sludge and bacteria an opportunity to form and grow:

MR. STEARNS. As a pipeline operator, would you expect to see regular pigging of low-stress lines where the oil moves at a slower velocity?

MR. HOSTLER. In the low-stress lines, yes, sir.

MR. STEARNS. Okay. Are you aware of any crude oil pipeline that is not pigged as a part of a regular corrosion maintenance program, leaving aside lines that may not be piggable due to sharp turns in the line or other structural obstacles?

MR. HOSTLER. Leaving aside those lines that have those types of problems, no, sir, I am not aware of any that are not pigged as a routine maintenance program.

4. The Senate Hearing

122. On September 12, 2006, the Committee on Energy and Natural Resources of the



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

United States Senate held a hearing on the Prudhoe Bay oil spill and shutdown. Steve Marshall

testified and admitted that BP had never pigged the EOA lines and that BP should have done so,

“we regret that we did not schedule a baseline pig run when BPXA assumed operations in 2001.”

In stark contrast, the President and CEO of Alyeska testified that Alyeska ran “a maintenance or

cleaning pig every 7 to 14 days and . . . an intelligent pig every 3 years.”

123. Marshall was subsequently replaced by BP. On October 31, 2006, The Wall

Street Journal reported that “BP plc (BP) Tuesday announced that it was replacing the head of its

troubled Alaska division . . . . Under the shift, current BP Alaska president Steve Marshall will

leave the division.”

124. PHMSA Administrator Barrett also testified and added to his prior testimony

before the House Energy Committee:

I think the operator [BP] is quite simply accountable for what happened. And we do not see conditions like this replicated in other lines on the North Slope or typically on other lines in the national pipeline transportation system.

5. The Congressional Investigation

125. The investigation by the House Energy Committee continued after the hearings.

On April 30, 2007, Representatives John D. Dingell (Michigan) (Chairman of the House Energy

Committee, “Dingell”), and Burt Stupak (Michigan) (Chairman of the Subcommittee on

Oversight and Investigations, “Stupak”), sent a letter to Malone expressing their concerns

regarding documents that emphasized budget pressures at BP.

The documents suggest that budget pressures were severe enough that some BP field managers were considering measures as draconian as reducing corrosion inhibitor to save money. BP provided e-mails that detail proposals to cut funding for corrosion inhibitor during at least two different years and in two different locations . . . . If senior BP managers were willing to consider turning off inhibitor at these locations, it suggests a budgetary environment in which other corrosion management activities may have been eliminated or reduced to a degree that may have directly affected corrosion of the portions of the oil transit lines (OTL) that experienced leaks last year.

Similarly, the documents suggest that corrosion- monitoring efforts such as smart pigging, coupon pulling, and digging up road crossings for visual inspection, were either reduced, put on hold, or “squeezed” in some cases due to budget constraints. In other



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

words, important action items related to health, safety, and the environment, were being delayed, or cut altogether, and that this was related to tight budgets possibly in an effort to maintain “flat lifting costs.”

K. Amendment No. 3 To The CAO

126. On April 27, 2007, PHMSA issued Amendment No. 3 to the CAO, finding it

necessary “in order to address immediate safety issues involving the Prudhoe Bay Pipelines.”

PHMSA had requested information regarding the corrosion mechanisms on the WOA and EOA.

BPXA provided a report for the WOA, but failed to provide a report for the EOA. Based on the

information PHMSA did receive, it stated:

BP has opined that the primary cause of the March and August 2006 failure was aggressive microbiologically induced corrosion (“MIC”). BP has indicated that MIC was promoted by the particular operating and internal characteristics of the WOA and EOA pipelines including, but not limited to, low crude oil flow velocities; the corrosivity of the material transported; the presence of water and sediments; an ineffective corrosion inhibitor program; and a lack of maintenance pigging. PHMSA’s review of BP’s March 30, 2007 report is ongoing.

L. BPXA Pled Guilty To A Criminal Violation Resulting From The Corrosion And Oil Spills In 2006

127. In connection with the oil spills at Prudhoe Bay, BPXA pleaded guilty on October

24, 2007 to a criminal violation of the federal Clean Water Act (the Guilty Plea”). BPXA agreed

to pay a $20 million fine in settlement of federal and state criminal violations. In a press release

issued that day, the U.S. Attorney for the District of Alaska, Nelson P. Cohen, said that the two

spills “were the result of BPXA’s failure to heed many red flags and warning signs of imminent

internal corrosion that a reasonable operator should have recognized.”

128. In the Guilty Plea, BPXA admitted that it knew of the corrosion and, intentionally

or with deliberate recklessness, failed to properly inspect, monitor and maintain the pipelines.

Specifically, BPXA admitted that,

• Both leaks resulted in substantial part from Microbial Induced Corrosion (“MIC”).

• MIC typically occurs in stagnant or relatively low flow conditions, such as the WOA and EOA pipelines that leaked.

• BPXA knew that the EOA line had sediment collecting in the pipe



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

prior to both spills.

• In 2005, BPXA was aware of increased corrosion activity in the WOA line that leaked.

• BPXA failed in light of these conditions to take necessary action to prevent the leaks.

• BPXA failed to clean the lines with a piece of equipment called a maintenance (or cleaning) pig and inspect the pipe for corrosion activity with a smart pig.

• The last time that the WOA line had been pigged (maintenance or smart) was 1998, eight years before the leak.

• The EOA line had not been pigged since 1990 and had never been pigged by BPXA.

• BPXA did not expend sufficient resources to address the complex issues of corrosion.

• BPXA was aware by 2004 that production upsets were occurring frequently as a result of processing heavier, more viscous oil at Gather [sic] Center 2 (GC2).

• BPXA knew that the EOA OTL also had sediment collecting in the pipe.

• BPXA was aware of sediment build-up on the EOA OTL prior to both spills.

• BPXA knew that it had insufficient inspection data on the EOA OTL.

• BPXA failed in light of these conditions to take necessary action to prevent the leaks on the OTLs. BPXA failed to clean the OTLs with a piece of equipment called a maintenance (or cleaning) pig and inspect the pipe for corrosion activity with a smart pig.

M. DOJ Filed A Civil Lawsuit On March 31, 2009, Based On BPXA’s Violations of The CAO

1. The DOJ Complaint (Filed After Plaintiffs’ 2008 Complaint)

129. On March 31, 2009, DOJ filed a civil complaint (the “2009 DOJ Action”) for

violations of the (i) Clean Water Act, 33 U.S.C. §§ 1251 et seq., (ii) Clean Air Act, 42 U.S.C. §§

7401-7671q, and (iii) Federal Pipelines Safety Laws, 49 U.S.C. § 6101 et seq. (Complaint

attached as Exhibit 2).

130. The alleged civil violations of the Clean Water Act relate to the spills in March



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

and August 2006 to which BPXA already had pled criminally guilty, in addition to new

allegations that BPXA failed to implement adequate Spill Prevention Control and

Countermeasures afterwards. The alleged violations of the Clean Air Act arise out of the alleged

improper removal of asbestos-containing materials from certain pipelines in the spring and

summer of 2006.

131. More relevant to this case, however, are the alleged violations of the Federal

Pipeline Safety Laws. These allegations include the same exact allegations made in this

complaint, namely that BPXA failed to comply with the CAO, inter alia, by failing to pig the

EOA by June 15, 2006.

132. Specifically, the 2009 DOJ Action alleged that, “BPXA violated the Order [CAO]

numerous times, including when”:

a. BP1 failed to begin weekly cleaning of the 34-inch pipeline

segment Gathering Center 1 to Skid 50 until about November 7, 2006, which was approximately 149 days after the Order’s [CAO] deadline.

b. BP failed to begin weekly cleaning of the 34-inch pipeline between Flow Station 1 and Skid 50 until about October 10, 2006, which was approximately 149 days after the Order’s [CAO] deadline.

c. BP failed to begin weekly cleaning of the 30-inch pipeline between Flow Station 2 and Flow Station 1 until about July 20, 2006, which was approximately 39 days [sic] after the Order’s [CAO] deadline.

d. BP failed to perform an internal inspection of the 34-inch pipeline between Gathering Center 1 and Skid 50 until about November 12, 2006, which was approximately 151 days after the Order’s [CAO] deadline.

e. BP failed to perform an internal inspection of the 34-inch pipeline between Flow Station 1 and Skid 50 until about October 18, 2006, which was approximately 124 days after the Order’s [CAO] deadline.

f. BP failed to perform an internal inspection of the 30-inch pipeline between Flow Station 2 and Flow Station 1 until about July 22, 2006, which was approximately 37 days after the Order’s [CAO] deadline.

1 The DOJ complaint does not define the term BP.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

g. BP failed to perform an internal inspection of the Lisburne pipeline until about June 30, 2006, which was approximately 15 days after the Order’s [CAO] deadline.”

2. The DOJ Consent Decree (Filed After Plaintiffs’ 2008 Complaint)

133. On July 20, 2011, BPXA entered into a consent decree (“Consent Decree”) to

settle the claims alleged by the DOJ in the complaint filed on March 31, 2009. (Exhibit 4

hereto). Pursuant to the Consent Decree, BPXA agreed to pay $25 million in civil penalties and

to make $60 million in improvements to its pipelines in Alaska.

134. The $25 million civil penalty amounts to $4,923 per barrel of oil spilled, the

largest per-barrel penalty to date for an oil spill under the Clean Water Act. A May 3, 2011 press

release issued by the DOJ quotes an Assistant United States Attorney for the District of Alaska

as stating that in entering into the Consent Decree, “BP Alaska admits that it cut corners and

failed to do what was required to adequately maintain its pipelines.”

135. The Consent Decree requires BPXA to enact significant improvements to its

safety and monitoring practices, including implementing a written Pipeline System-Wide

Integrity Management Program (“IM Program”). The Consent Decree specifically sets forth the

following requirements, which are directed towards preventing a future oil spill:

• Pipeline Inspection: BPXA must smart pig all of its piggable lines every five years and maintenance pig its piggable lines at least twice a year. For lines that are not piggable, BPXA must use specified ER Probes or corrosion weight loss coupons (“Coupons”) in the correct place in every pipeline (e.g. if the corrosion occurs at the bottom of the pipeline, the ER Probe or Coupon must be placed in the bottom of the pipeline) and frequently monitor the data collected.

• Risk Prevention and Mitigation: BPXA must implement Risk Prevention and Mitigation procedures to prevent and mitigate corrosion and other threats to the integrity of the pipelines. This element is specifically designed to: (1) determine the corrosion mechanism(s) on each pipeline; (2) optimize corrosion control (e.g. test corrosion inhibitors, adjust dosage, etc.); and (3) evaluate the effect of changing operational conditions including, but not limited to, flow velocities and changing fluid characteristics. Additional requirements include converting the 10 riskiest non-piggable lines into piggable lines.

• Pipeline System Repair: BPXA must promptly (within 180 days) act on all anomalous conditions BPXA discovers in the pipelines, and either: (a) repair those anomalies that could reduce a pipeline’s integrity; (b) derate the Maximum Operating Pressure of the pipeline (i.e. slow the travel speed of the oil within the pipeline); or (c) remove the pipeline from operational service.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

• Design Effective Leak Detection System: BPXA must test various leak detection systems and must submit a report analyzing the scheme most likely to prove effective.

• Risk Based Assessment and Ranking: BPXA must submit to the government for approval a Risk Based Assessment Procedure providing a mechanism for BPXA to perform a relative risk-ranking of all pipelines.

• Data and Information Collection: BPXA must develop and submit to the government for approval a procedure to identify, collect, and document data and information regarding the pipelines.

• Geographic Information System: BPXA has initiated the development of a Geographic Information System to organize and display information about the conditions and characteristics of its pipelines. The government will have direct access to the system.

• Continual Program Improvement: Within one year, BPXA must develop, submit, and implement procedures for the continual improvement of its System-Wide IM Program.

136. Most of the measures required by the Consent Decree rectified and addressed the

wrongful conduct that caused the spill.

N. The State of Alaska Sued BPXA After Plaintiffs’ 2008 Complaint Because The Corrosion Monitoring And Management System Violated State Law And Regulations

137. On March 31, 2009, the same day that DOJ filed its action, the State of Alaska

also filed a civil lawsuit as a result of the March and August 2006 oil spills. The basis of the

lawsuit was that BPXA’s corrosion monitoring and management system violated state law, and

that BPXA knew or was deliberately reckless. The lawsuit is ongoing and has not been resolved.

1. BPXA’s Failure To Comply With Its Spill Prevention Plan Violated State Law

138. Pursuant to the law of the State of Alaska, AS § 46.04.030(b), an operator of

pipelines and oil production facilities such as BPXA is required to have an approved oil

discharge prevention and contingency plan. BPXA operated Prudhoe Bay pursuant to such a

plan (the “Spill Prevention Plan”).

139. Section 2.1.5 of the Spill Prevention Plan provided that BPXA would monitor the

pipelines “through a comprehensive inspection process designed and executed by the Corrosion,

Inspection and Chemicals group (CIC) . . . . CIC monitors corrosion rates on pipelines, adjust



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

[sic] corrosion inhibitor rates and identifies areas for repair or decommissioning based upon

regular inspections.”

140. However, as set forth in detail in the State of Alaska’s complaint, “BPXA failed

to adequately monitor corrosion rates [and] adjust corrosion inhibitor levels in the OTLs so

as to prevent corrosion as required by its approved [Spill Prevention Plan].” (Alaska Complaint,

attached as Exhibit 3, ¶¶ 142-145).

141. Failure to comply with the Spill Prevention Plan constitutes a violation of Alaska

State law pursuant to AS § 46.04.030(g).

142. The facts alleged in Alaska’s complaint, if true, establish that BPXA failed to

comply with its Spill Prevention Plan, and that these violations occurred knowingly or with

deliberate recklessness even though the causes of action pursued by Alaska may have a lower

culpability requirement.

143. With respect to BPXA’s failure to adequately monitor corrosion rates, Alaska

relied on the October 2007 Guilty Plea by BPXA to allege that BPXA “knew that it had

insufficient inspection data on the EOA OTL.” (Alaska Complaint ¶¶ 49-51). Further, BPXA

had memoranda from the prior owner of the EOA OTL (ARCO) that said that BPXA lacked a

baseline corrosion measurement for that line and, nevertheless, chose to conduct a “very small

number” of corrosion inspections that only covered small portions of the OTL and never

constituted a comprehensive review. (Alaska Complaint ¶ 50).

144. BPXA’s culpability in violating the Spill Prevention Plan due to insufficient

corrosion data on the EOA was even more egregious because BPXA knew that the EOA OTL

was subject to highly corrosive conditions – including low flow rates. As set forth in the Alaska

Complaint, BPXA “knew” that the flow rate in the EOA OTL was six inches per second, which

was significantly less than the minimum rate of one meter per second which CIC had concluded

“should be avoided if [corrosion] inhibitors are to provide satisfactory protection.” (Alaska

Complaint ¶ 51).

145. BPXA also failed to adequately monitor corrosion rates because it knowingly or



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

with deliberate recklessness failed to properly use corrosion coupons. BPXA installed the

coupons in locations in the pipeline that BPXA knew would not adequately capture corrosion

rates. Instead of installing the coupons on the bottom of the pipe, where sediment and water are

most likely to accumulate and cause corrosion, BPXA placed the coupons into the flow – the

middle or top of the pipe (Alaska Complaint ¶¶ 56-57).

146. In 2005, BPXA acknowledged the importance of coupon placement in a published

paper, stating that “the choice of monitoring location(s) is therefore one of the most important

decisions a corrosion engineer has to make.” (Alaska Complaint ¶ 57). Ten years before, in

1995, a BPXA document had admitted that coupons in the GC2 – GC1 line would not capture

corrosion on the bottom of the pipe: “[t]he team agreed that these coupons would not likely be

representative of the active corrosion in the bottom of the GC2/1 transit line due to difference in

geometry and flow condition.” (Alaska Complaint ¶ 58).

147. BPXA’s limited UT testing also failed to provide adequate inspection data.

According to the Complaint, BPXA conducted “a very small number” of UT inspections in the

WOA, and an even smaller number in the EOA. The WOA inspections were largely

concentrated in only one area, with the majority in a single 150-foot section. No UT inspections

were carried out within 800 feet of the March 2006 spill location. Moreover, UT inspections

could not detect pitting in underground caribou crossings, which is where the March leak

occurred.

148. For the EOA OTL, BPXA only collected information on about 45 one-foot

sections of the approximately 3-mile pipeline. (Alaska Complaint ¶¶ 60-61). BPXA’s EOA

Incident Investigation Report concluded that the number of UT measurements “were not

sufficient to accurately represent the true condition of the line.” (Alaska Complaint ¶ 62).

149. With respect to BPXA’s failure to adequately adjust corrosion inhibitor levels,

BPXA knew in May 2005 that the WOA OTL had 30% lower corrosion inhibitor levels than

other pipelines. (Alaska Complaint ¶ 65). BPXA further knew in May 2005 that bacteria had

increased at GC2, and that GC2’s produced-water had the lowest toxicity against bacteria in the



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

system. Id. BPXA did not add additional corrosion inhibitor to the WOA OTL, even though in

2002 BPXA did decide to add additional inhibitor to another type of pipeline that carried

produced water rather than crude oil. (Alaska Complaint ¶ 64).

2. The Leak Detection System

(a) The Leak Detection System Violated Alaska State Law And Regulations

150. BPXA’s Leak Detection System also violated state law and regulations: “BPXA

failed to operate and maintain its leak detection system on the OTLs in compliance with its

approved [Spill Prevention Plan] and as required by 18 AAC § 75.055 (1992).” (Alaska

Complaint ¶ 137).

151. Section 75.055 of the Alaska Administrative Code (AAC) sets forth the regulatory

requirements concerning leak detection systems, namely, “if technically feasible, the continuous

capability to detect a daily discharge equal to not more than one percent of daily throughput.”

Section 2.1.9 of BPXA’s Spill Prevention Plan represented that detecting a 1% discharge was

technically feasible. (Alaska Complaint ¶ 131).

152. The leak detection system principally relied on automatic sonic flow and turbine

flow meters that compared the flow rate entering a given segment versus the flow rate out of that

same segment. Theoretically, the measured flow rate would be identical at both ends of a

segment. However, due to BS&W excursions this was not the case and so the system was

designed to identify a 1% leak, or greater, over 24 hours. The measurements were carried out

electronically.

153. However, as set forth in the Alaska Complaint, BPXA knew that its leak detection

system required clean pipelines, free of sediment, to operate properly and to detect a daily

discharge of 1%, or more, of the crude oil flow in the OTL. (Alaska Complaint ¶ 134).

Detection of a 1% discharge was required by 18 AAC § 75.055.

154. BPXA also “knew that the EOA OTL . . . had sediment collecting in the pipe . . . .

Approximately six inches of sediment and residual oil were found on the bottom of the [pipe that

leaked in March 2006]. BPXA was aware of sediment build up on the EOA OTL prior to both



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

spills.” (Plea Agreement at 10-11). Accordingly, BPXA knew that the sediment accumulated in

the pipelines prevented compliance with the minimum requirements set forth by Alaska

regulations for the proper operation of the leak detection system.

155. BPXA’s leak detection system also violated Section 2.5.8 of the “Spill Prevention

Plan,” thus violating Alaska regulations that require operative compliance. Section 2.5.8

provided that “[l]eaks too small to be detected by an automatic leak detection system would be

detected by visual inspection, generally within 12 hours.” The March 2006 spill went undetected

for 5 days.

(b) Defendants Knew Or Were Deliberately Reckless In Not Knowing That The Leak Detection System Violated Alaska Laws and Regulations

156. The Incident Report dated March 31, 2006 established that the leak detection

system had failed because the leak went undetected even though it exceeded 1% in one 24 hour

period. The data set forth in the Incident Report makes clear that the leak equaled 1% or more –

the maximum flow rate of the hole in the GC2-GC1 pipe had been 1,000 to 1,300 barrels of oil

per day, out of 100,000 bopd, or 1% to 1.3%. Yet, “the leak detection did not sound on March 1

or March 2,” when the leak was discovered.

157. Critically, the automatic leak detection alarms had gone off during the week

preceding March 2 – four times between February 25 and February 28. But because “GC2 had a

history of high BS&W,” which affects the flow along the pipe, the alarms were disregarded and a

“tuning adjustment” was made on February 28. Effectively, BPXA turned off the automatic leak

detection system because it knew that the OT-21 line had so much sediment and water that the

leak detection system was unreliable. The visual inspections, which were supposed to back up

the automatic meters, also failed to detect the leak. The whole system simply failed.

VII. CLASS ACTION ALLEGATIONS

158. Lead Plaintiffs bring this action as a class action pursuant to Federal Rule of Civil

Procedure 23(a) and (b)(3) on behalf of a Class, consisting of all those who purchased or

otherwise acquired BP ordinary shares and ADRs between June 30, 2005 and August 4, 2006,



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

inclusive, and who were damaged thereby. Excluded from the Class are (i) Defendants; (ii) any

subsidiaries and affiliates of the Corporate Defendants; (iii) the officers and directors of the

Corporate Defendants and its subsidiaries and affiliates; (iv) members of the immediate families

of the Individual Defendants and their legal representatives, heirs, successors or assigns; (v) any

entity in which Defendants have or had a controlling interest; and (vi) any benefit plan on behalf

of employees of the Corporate Defendants and its subsidiaries or affiliates.

159. The members of the Class are so numerous that joinder of all members is

impractical. The exact number of Class members is unknown to Lead Plaintiffs at this time and

can only be ascertained through appropriate discovery. Record owners and other members of the

Class may be identified from records maintained by BP or its transfer agent and may be notified

of the pendency of this action by mail, using the form of notice similar to that customarily used

in securities class actions.

160. There is a well-defined community of interest in the questions of law and fact

involved in this case. Questions of law and/or fact common to the members of the Class which

predominate over questions which may affect individual Class members include:

(a) Whether the Exchange Act was violated by Defendants;

(b) Whether Defendants omitted and/or misrepresented material facts;

(c) Whether Defendants’ statements omitted material facts necessary to make

the statements made, in light of circumstances under which they were made, not misleading;

(d) Whether Defendants knew or deliberately recklessly disregarded that their

statements were false and misleading;

(e) Whether the price of BP’s ordinary shares and ADRs was artificially

inflated as a result of Defendants’ misrepresentations and/or omissions; and

(f) Whether disclosure of Defendants’ wrongdoing caused class members to

suffer an economic loss and damages.

161. Lead Plaintiffs’ claims are typical of those of the Class because Lead Plaintiffs

and the Class sustained damages from Defendants’ common course of wrongful conduct.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

162. Lead Plaintiffs will adequately protect the interests of the Class and have retained

counsel who are experienced in class action securities litigation. Lead Plaintiffs know of no

interests which conflict with those of the Class.

163. A class action is superior to all other available methods for the fair and efficient

adjudication of this controversy since joinder of all members is impracticable. As the damages

suffered by individual Class members may be relatively small, the expense and burden of

individual litigation make it impossible for members of the Class to individually redress the

wrongs done to them. There will be no difficulty in the management of this action as a class

action.

VIII. FRAUD ON THE MARKET PRESUMPTION OF RELIANCE

164. At all relevant times, the market for BP’s ordinary shares and ADRs was an

efficient market for the following reasons, among others:

(a) BP’s ordinary shares and ADRs met the requirements for listing, and were

listed and actively traded on the LSE and NYSE, both highly efficient markets;

(b) On average BP’s ordinary shares and ADRs traded millions of shares and

receipts per day during the Class Period;

(c) As a regulated issuer, BP filed periodic public reports with the SEC and

the NYSE;

(d) BP regularly communicated with public investors via established market

communication mechanisms, including through regular disseminations of press releases on the

national circuits of major news services and through other wide-ranging public disclosures, such

as communications with the financial press an other similar reporting services; and

(e) BP was followed by securities analysts and many brokerage firms who

issued reports which were distributed to the financial community. Each of these reports was

publicly available and entered the public marketplace.

165. As a result of the foregoing, the market for BP’s ordinary shares and ADRs

promptly digested current information from all publicly available sources and reflected such



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

information in the price of BP’s ordinary shares and ADRs. Under these circumstances, all

purchasers of BP’s ordinary shares and ADRs during the Class Period suffered similar injury

through their purchase of those securities at artificially inflated prices, and a presumption of

reliance applies.

IX. SCIENTER

166. Each of the Defendants had actual knowledge of the misrepresentations and

omissions of material facts set forth herein, or acted with deliberate reckless disregard for the

truth in that they failed to ascertain and to disclose such facts, even though such facts were

available to them. Defendants’ material representations and/or omissions were made knowingly

or with deliberate recklessness and for the purpose and effect of concealing Defendants’

operations and business affairs from the investing public, thereby supporting the artificially

inflated price of BP’s ordinary shares and ADRs. As demonstrated by Defendants’ statements

and conduct throughout the Class Period, if Defendants did not have actual knowledge of the

misrepresentations and omissions alleged, Defendants were deliberately reckless in failing to

obtain such knowledge by deliberately refraining from taking those steps necessary to discover

whether those statements and conduct were deceptive and fraudulent.

167. In particular, the following evidence, set forth in detail above, raises a strong

inference of scienter:

• On October 24, 2007, BPXA entered a guilty criminal plea for its conduct in connection with the allegations in this complaint; specifically the oil spills on March and August 2006 and the shut down of Prudhoe Bay in August 2006 (¶¶ 127-128);

• The Board was informed on or about May 5, 2006 that, “[i]nspections . . . indicated that the corrosion which led to the leak may not [have been] an isolated case. Further smart pig inspections and maintenance pig runs [were] required to completely verify that all pipelines meet integrity standards” (¶ 94);

• BP was informed in 2004 of severe corrosion problems at Prudhoe Bay by letter from Charles Hamel; Defendants failed to take any corrective action (such as pigging and smart pigging the lines) and, instead, sought to identify the whistleblowers (¶¶ 58-59);

• BPXA was alerted by the Coffman report in 2001 that it should pig and smart pig its pipelines; Defendants took no corrective action



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

(such as pigging and smart pigging the lines) and, instead, suppressed the Coffman report (¶¶ 49-57);

• In September 2005, Defendants knew that the WOA transit line that caused the 200,000 gallon oil spill in March 2006 exhibited evidence of high and rapidly accelerated corrosion; BP took no corrective action (such as pigging and smart pigging the lines) (¶¶ 60-65);

• BPXA knew that production upsets were occurring more frequently in the OT-21 line by 2004 and that the EOA OTL had sediment build ups, both highly corrosive conditions (¶ 128);

• BPXA knew it had insufficient inspection data on the EOA OTL (¶¶ 128, 132, 143, 147-148);

• BPXA’s corrosion monitoring and leak detection system were in violation of, and not in compliance with, BPXA’s own Spill Prevention Plan (¶¶ 138-157);

• BPXA’s corrosion monitoring and leak detection system were in violation of, and not in compliance with, Alaska State laws and regulations (¶¶ 138-157);

• On March 15, 2006, PHMSA issued the CAO and mandated that BPXA take a series of corrective actions, including pigging the EOA line that ultimately caused the August oil spill and led to the shutdown of Prudhoe Bay; Defendants violated the CAO, among other things, by not pigging the EOA line within the mandatory deadline (¶¶ 81-90, 96-102, 108-115, 126);

• Hayward knew that BPXA was in violation of the CAO, as set forth in the briefing memorandum prepared for him on or about June 12, 2006 (¶¶ 96-99);

• PHMSA administrator Barrett in testimony before Congress stated that (i) BP’s conduct was “mystifying;” (ii) he could not understand why BP did not address the corrosion; (iii) most pipeline operators demonstrate a higher standard of care than BP; and (iv) BP had no explanation for its conduct or the level of corrosion in its pipelines (¶ 120);

• PHMSA administrator Barrett further testified before Congress that he did not know of any other instance comparable to BP’s failure to pig and smart pig the transit lines at Prudhoe Bay (¶ 124);

• U.S. Congressman Barton (Chairman of the House Energy Committee) wrote a letter to BP stating that the shut down of Prudhoe Bay due to excessive corrosion of its oil transit pipelines “contradicts everything the Committee has been told” by BP (¶ 116);

• The head of the Corrosion division at BP in Alaska (Woollam) “took the Fifth” when testifying before Congress and asked about



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

BP’s corroded pipelines at Prudhoe Bay (¶ 118);

• According to U.S Congressman Walden, the House Energy Committee learned from several sources that numerous red flags were raised about the integrity of the Prudhoe Bay pipelines while Woollam was in charge of the corrosion division group, including the Coffman report in 2001; yet, in 2002 Woollam initiated and implemented a plan to reduce the manpower of a key pipeline corrosion monitoring team by 25 percent (¶ 118);

• Kevin Hostler, President and CEO of Alyeska Pipeline Service, testified before Congress that he was not aware of any crude oil pipeline that is not pigged as a part of a regular corrosion maintenance program (¶ 121);

• According to Congressman Dingell and Stupak of the House Energy Committee, internal BP documents show that (i) budget pressures led to the reduction of corrosion inhibitor to save money, and (ii) corrosion- monitoring efforts such as smart pigging, coupon pulling, and digging up road crossings for visual inspection, were either reduced, put on hold, or “squeezed” in some cases due to budget constraints (¶ 125).

X. LOSS CAUSATION

168. During the Class Period, the price of BP’s ordinary shares and ADRs was

artificially inflated as a result of Defendants’ omissions of material fact and materially false and

misleading statements. When the falsity of the materially false and misleading statements was

revealed, and the material omissions disclosed, the price of BP’s ordinary shares and ADRs fell

precipitously as the prior artificial inflation was promptly and completely eliminated from the

price of those securities. Lead Plaintiffs and the Class incurred an economic loss (damages

under the securities laws) as a result of Defendants’ material omissions and materially false and

misleading statements.

169. By making materially false and misleading statements and omissions regarding

the maintenance and operating condition of Prudhoe Bay and the existing risks to the continuous

and regular flow of oil from Prudhoe Bay, Defendants improperly inflated the price of BP’s

ordinary shares and ADRs. Specifically, Defendants falsely and misleadingly asserted that they

operated Prudhoe Bay in compliance with the requisite laws and regulations. Defendants made

additional false and misleading statements and omissions regarding the safety of BP’s

operations, and failed to disclose the risk that the corrosion in the pipelines at Prudhoe Bay could



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

lead to a shutdown or dramatic reduction in oil production. These materially false and

misleading statements and omissions caused and maintained the artificial inflation in the price of

BP’s ordinary shares and ADRs during the Class Period until the truth of the operating condition,

deterioration of the pipelines, and the resultant shutdown in production at Prudhoe Bay were

publicly disclosed and accurately reflected in the price of BP’s ordinary shares and ADRs.

170. At the Congressional hearing on September 7, 2006, PHMSA Administrator

Barrett testified that, “[i]t was a result of the pigging that we ordered that BP discovered the wall

loss and the leaks on a line segment in the eastern operating area that led to the production

shutdown on 6 August.”

171. For purposes of alleging loss causation, the price decline in BP’s ordinary shares

and ADRs was a direct result of the nature and extent of materially false and misleading

statements and omissions revealed to investors and the market on Sunday August 6, and Monday

August 7, 2006. By the time the market opened on Monday August 7, 2006, BP had announced

the shutdown of oil production at Prudhoe Bay due to the discovery of additional corrosion in

more pipelines and an additional oil spill. As a result of this announcement, (i) BP’s ordinary

shares fell 13.5 pence (from a closing price of 636 pence on August 4 to a closing price of 622.5

pence on August 7), or 2.1 percent on extraordinarily heavy volume of 94.5 million shares, and

(ii) BP’s ADRs dropped $2.09 (from a closing price of $72.54 on August 4 to a closing price of

$70.45 on August 7), or 2.8 percent, on volume of 6.1 million shares.

172. More specifically, in a news story published on August 7 at 9:02 a.m. in New

York and titled, “U.K. Stocks Slide, Led by BP; BHP Billiton, Rio Tinto Decline,” Bloomberg

reported the following:

Aug. 7 (Bloomberg) – U.K. stocks declined, paced by BP plc after Europe’s largest energy company said it will close the biggest U.S. oil field.

* * * Shares of BP fell 14.5 pence, or 2.3 percent, to 621.5, its biggest decline in almost two months. The company said it is shutting the Prudhoe Bay oil field in Alaska because of pipeline corrosion and a leak. The site accounts for 8 percent of U.S. production.

* * *



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

Crude oil for September delivery rose as much as 2.6 percent to $76.67 a barrel in New York.

173. The market focus on the BP shutdown of Prudhoe Bay continued throughout the

day. In a news story published at 12:36 p.m. in New York and titled, “BP Shuts Down Prudhoe

Bay, U.S.’s largest Oil Field,” Bloomberg said:

‘Big Effect’

Crude oil for September delivery rose as much as $2.09 to $76.85 a barrel on the New York Mercantile Exchange and traded at $76.50 at 5:14 p.m. London time . . . . BP shares fell 13.5 pence to 622.5 pence in London. . . .

‘Sizable Flow’

“Prudhoe Bay is a sizable flow and is key to the U.S. market,”said Anthony Nunan, assistant general manager for risk management at Mitsubishi Corp. in Tokyo. “It should have a fairly big effect.”

* * * “We need to understand why the corrosion is as severe as it is,” [BP spokesman Ronnie] Chappel said. “We do not have a firm restart date at this time.”

174. By the end of the day on August 7, 2006 the news of BP’s shutdown of Prudhoe

Bay had been the main factor driving the markets. Bloomberg summed up the day’s trading

activity in an article published at 5:00 p.m. and titled, “U.S. Markets: Oil Jumps, Stocks Drop

After BP Cuts Alaska Crude:”

Aug. 7 (Bloomberg) – Crude oil surged more than $2 a barrel and U.S. stocks slid after BP plc said it will shut Alaska’s Prudhoe Bay oil field, the largest in the U.S., because of pipeline corrosion and a leak.

175. Ordinary shares of BP on August 7, 2006 closed at 622.5 pence in London,

dropping 13.5 pence from 636 pence on August 4, or 2.1 percent on extraordinarily heavy

volume of 94.5 million shares. Average daily volume for the ensuing 3 month period was

approximately 59.4 million, or 60 percent less. The Company’s ADRs that trade in the NYSE

dropped from $72.54 to $70.45, or 2.8 percent, on volume of 6.1 million shares, which was

almost double the average volume of 3.6 million shares.

176. BP’s shares continued to slide on August 8, 2006. Bloomberg reported in an



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

article titled “U.K. Stocks Erase Advance; Scottish & Newcastle, BP Decline,” published at 8:58

a.m., as follows,

BP, Europe’s biggest oil company, slid 14 pence, or 2.3 percent, to 608.5, its biggest decline in almost two months. The stock was lowered to “reduce” from “accumulate” by Antoine Leurent, an analyst at KBC securities.

The share price estimate was cut to 543 pence from 670. BP has the highest weighting on the FTSE 1000, accounting for more than 8 percent of the index.

BP yesterday said it would close the largest U.S. oil field indefinitely due to corrosion and leakage at Alaska’s Prudhoe pipeline.

177. A similar story also published by Bloomberg at 1:10 p.m. (after the London

close), highlighted BP’s fall from grace.

BP’s Market Value Falls Below Shell on Alaska Closure

Aug. 8 (Bloomberg) – BP Plc’s market value slid below that of it rival Royal Dutch Shell Plc, making it Europe’s second-largest oil company, as the shutdown of Alaska’s largest oil field became the latest headache for BP’s U.S. operations.

Credit Suisse Group analysts lowered their forecasts for BP’s 2006 per-share earnings by 1.7 percent because of the stoppage at Prudhoe Bay oil field, where BP gets 2.5 percent of its global production.

178. Also on August 8, 2006, Malone, Chairman and President of BP America,

announced at a press conference that “it has been necessary to take this drastic action of [a]

shutdown of the Prudhoe Bay” and that BP has “taken the decision to replace the main oil lines

at Prudhoe Bay” in order to ensure “the integrity of the field.” CNNMoney.com that same day

reported that the shutdown of Prudhoe Bay was the first of its kind and its impact on consumer

gas prices and oil futures had pushed both to near-record highs.

179. Ordinary shares of BP on August 8 closed at 614 pence in London, dropping 8.5

pence, or 1.4 percent on extraordinarily heavy volume of 190 million shares, three time average

daily volume of approximately 59.4 million. The Company’s ADRs that trade on the NYSE

dropped from $70.45 to $70.14, or 2.8 percent, on heavy volume of 4.7 million shares. As a

result, investors suffered billions of dollars in losses between August 7 and 8, 2006.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

XI. INAPPLICABILITY OF STATUTORY SAFE HARBOR

180. The statutory safe harbor provided by forward looking statements under certain

circumstances does not apply to any of the allegedly false statements pleaded in this complaint.

The statements alleged to be false and misleading herein relate to then-existing facts and

conditions.

XII. CAUSES OF ACTION

COUNT I

Violation of § 10(b) of the Exchange Act And Rule 10b-5Promulgated Thereunder Against BP, BPXA, Johnson, and Browne

181. Lead Plaintiffs repeat and reallege the preceding allegations as if fully set forth

herein. This Count is asserted against all Defendants for violations of Section 10(b) of the

Exchange Act and Rule 10b-5 promulgated thereunder.

182. During the Class Period, Defendants, individually, and in concert, directly and

indirectly, by the use and means of instrumentalities of interstate commerce, the mails and the

facilities of a national securities exchange, employed devices, schemes, and artifices to defraud,

made untrue statements of material fact and/or omitted to state material facts necessary to make

statements made not misleading, and engaged in acts, practices and a course of business which

operated as a fraud and deceit upon Class members in violation of Section 10(b) of the Exchange

Act and Rule 10b-5(b) promulgated thereunder. Defendants’ false and misleading statements

and omissions and deceptive scheme and course of conduct were made with scienter and were

intended to and did (i) deceive the public, including Lead Plaintiffs and the other members of the

Class, (ii) artificially create the market for, and inflate and maintain the market price of, BP’s

ordinary shares and ADRs; and (iii) cause Lead Plaintiffs and members of the Class to purchase

BP’s ordinary shares and ADRs at inflated prices.

A. Materially False And Misleading Statements And Omissions

1. BP’s 2005 False And Misleading Statements and Omissions Concerning Compliance With “Best Environmental Practices”

183. On June 30, 2005, BP filed its 2004 Annual Report with the SEC on Form 20-F



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

(“BP 2004 Annual Report”). The BP 2004 Annual Report, under “United States Regional

Review,” said:

throughout 2004, BP continued to comply with a plea agreement with the U.S. Justice Department to develop, implement and maintain a nationwide environmental management system (EMS)consistent with the best environmental practices at Group facilities engaged in oil exploration, drilling and/or production in the US and in its territories. BP fully implemented EMSs in Alaska and Lower 48 exploration and production performance units during 2003 and met the requirement to spend at least $15 million on the programme.

184. The statement that BP implemented and maintained a nationwide environmental

management system in Alaska, “consistent with the best environmental practices,” was

materially false and misleading, because:

(a) BP’s environmental practices were criminal and in violation of the Clean

Water Act (¶¶ 127-136);

(b) the pipelines at Prudhoe Bay were under-inspected, under-maintained, and

subject to a severe risk of corrosion-related-failure, including the risk of complete shutdown of

all production at Prudhoe Bay (¶¶ 81-85; 128-157);

(c) corrosion maintenance and prevention efforts had been severely curtailed

(¶ 118);

(d) BP and BPXA had been warned that the pipelines were severely corroded,

including BP’s Board of Directors which had received a letter in May 2004 warning “of serious

corrosion problems” and predicting a “major catastrophic event” (¶ 58);

(e) BPXA had been warned that pigging and smart pigging were necessary to

adequately monitor, inspect and maintain the pipelines (¶¶ 49-57, 81-85);

(f) despite the repeated warnings of increased corrosion and dangers in not

pigging, no corrective action was taken (¶¶ 81-85, 96-102, 108-115, 126);

(g) BPXA’s corrosion monitoring and leak detection system violated and

failed to comply with Alaska State laws and regulations (¶¶ 138-157); and

(h) BPXA’s corrosion monitoring and leak detection system violated and



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

failed to comply with BPXA’s own Spill Prevention Plan, which itself constituted another

violation of Alaska law and regulations (¶¶ 138-157).

2. False and Misleading Statements and Omissions By Johnson On Behalf Of BPXA After March 2, 2006 About The Level Of Corrosion And Subsequent Efforts To Avoid Another Spill

(a) Defendant Johnson Falsely Claimed That TheCorrosion Was Low And Manageable

185. On March 15, 2006, Defendant Johnson, as Senior Vice President of BPXA, made

the following statements in an article entitled, “Oil Company Knew Of Corrosion In Alaska

Pipeline Months Before Spill.”

Johnson said corrosion was seen in the 34 inch oil transit line [that caused the March 2 Oil Spill] in a September inspection but it appeared to be occurring at a “low manageable corrosion rate.”

186. The statement by Johnson was false and misleading because,

(a) the corrosion rate was 32 MPY, and according to Lead Plaintiffs’ expert,

Dr. Smart, a corrosion rate of 32 MPY was “high” for the OT-21 line. The acceptable corrosion

rate should not have exceeded a “few mls per year” (¶¶ 60-66);

(b) Dr. Smart opined that BPXA seriously mismanaged the corrosion rate

because: (a) the on-set of corrosion due to water stratification in the pipeline was never

considered as part of the corrosion analysis; (b) the corrosion inhibitor program in the field did

not control the corrosion in the pipeline; (c) corrosion monitoring depended on spot checks using

Ultrasonic Thickness testing where they could get to it, and did not focus on the most likely

internal corrosion locations; (d) in-line inspection using instrumented pigs, a technology which

was well developed at the time of the leaks, and which could have detected the corrosion over

100% of the pipe wall, were not run (¶¶ 68-69);

(c) Dr. Smart opined that the corrosion was not manageable because BPXA

failed to run maintenance pigs (¶ 68);

(d) a corrosion rate of 32 MPY was the “highest” in six years and

corresponded to the “highest” of three levels of corrosion rates as measured by BPXA (¶¶ 60-

66);



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

(e) BPXA’s internal documents, newly alleged in this Compaint, show that

BPXA viewed the corrosion rate prior to the September 2005 inspection as “low and

manageable,” but not after the September 2005 inspection (¶¶ 62-63);

(f) BP’s April 2005 Internal Audit, newly alleged in this Complaint,

established a corrosion rate of less than 2 MPY as the “operating criterion,” while the

“September inspection” referenced by Defendant Johnson had found a corrosion rate ten times

higher, 32 MPY (¶ 66);

(g) in September 2005 there had been a sharp and rapid spike in the corrosion

rate to 32 MPY (¶¶ 60-64);

(b) Johnson Falsely Claimed That The Highly Corrosive Conditions Were Unique To The WOA Line

187. The March 15, 2006 Associated Press article also said that,

Spill investigators found significant damage especially in low spots of the pipe that likely occurred within the last six to nine months. Similar problems have not been found in other lines downstream and elsewhere in Prudhoe Bay, and Johnson said it appears thehighly corrosive conditions were unique to that line . . . .

188. The statement by Johnson that it appeared that the highly corrosive conditions

were unique to the failed line was false and misleading because,

(a) an August 31, 2006 letter by BPXA’s Vice President of Regulatory Affairs

& Compliance (Sandy Stash), newly alleged in this Complaint, admitted that, “the causal factors

that appear to most strongly influence the pitting corrosion are flow velocity and inclination of

the pipeline, in the presence of water and solids. These factors have created an environment that

could lead to Microbiologically Induced Corrosion and/or Under Deposit Corrosion. These

factors are not substantially different between the Eastern Operating Area (EOA) and Western

Operating Area (WOA)” (¶ 47);

(b) internal BPXA documents, newly alleged in this Complaint, show that BP

considered that “there [was] a certain amount of similarity between the EOA and WOA oil

transit pipelines. Because of these similarities it was believed the pipelines also had similar

conditions” (¶ 89);



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

(c) internal BPXA documents, newly alleged in this Complaint, further show

that BP considered the WOA and EOA lines sufficiently similar, and to have been operating

under sufficiently similar environmental and corrosive conditions, to ascribe testing data from

the WOA line to the EOA line, especially for internal corrosion purposes (¶ 89);

(d) according to PHMSA, the WOA and EOA were subject to similar

corrosive conditions, specifically, “low crude oil flow velocities; the corrosivity of the material

transported; the presence of water and sediments; an ineffective corrosion inhibitor program; and

a lack of maintenance pigging” (¶ 126);

(e) BPXA admitted in the Plea Agreement that it “knew that it had

insufficient inspection data on the EOA OTL” (¶¶ 128, 143); and

(f) The CAO, which was addressed to Johnson, had determined that “all three

pipelines were constructed around the same time, operate[d] in similar environmental conditions,

transport[ed] the same quality crude oil that contributed to the cause of the internal corrosion in

PBWOA, and [were] operated and maintained in a similar manner” (¶ 86).

(c) Johnson Falsely Claimed That No Other OTL Had The Same Combination Of Factors

189. Petroleum News published an interview with Defendant Johnson on May 14,

2006, in which she made the following false and misleading statement:

We’ve looked at all of the oil transit lines . . . . none other has the same combination of factors . . . . bacteria in the facility, low flow rate and low corrosion inhibitor carry over . . . .

190. Defendant Johnson’s statement was false and misleading because,

(a) the letter by Sandy Stash – BPXA’s Vice President of Regulatory Affairs

& Compliance – dated August 31, 2006, admitted that, “the causal factors that appear to most

strongly influence the pitting corrosion are flow velocity and inclination of the pipeline, in the

presence of water and solids. These factors have created an environment that could lead to

Microbiologically Induced Corrosion and / or Under Deposit Corrosion. These factors are not

substantially different between the Eastern Operating Area (EOA) and Western Operating Area

(WOA)” (¶ 47);



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

(b) internal BPXA documents show that BP considered that “there [was] a

certain amount of similarity between the EOA and WOA oil transit pipelines. Because of these

similarities it was believed the pipelines also had similar conditions” (¶ 89);

(c) internal BPXA documents further show that BP considered the WOA and

EOA lines sufficiently similar, and to have been operating under sufficiently similar

environmental and corrosive conditions, to ascribe testing data from the WOA line to the EOA

line, especially for internal corrosion purposes (¶ 89);

(d) according to PHMSA, the WOA and EOA were subject to similar

corrosive conditions, specifically, “low crude oil flow velocities; the corrosivity of the material

transported; the presence of water and sediments; an ineffective corrosion inhibitor program; and

a lack of maintenance pigging” (¶ 126);

(e) BPXA admitted in the Plea Agreement that it “knew that it had

insufficient inspection data on the EOA OTL” (¶¶ 128, 143); and

(f) The CAO, which was addressed to Johnson, had determined that “All

three pipelines were constructed around the same time, operate[d] in similar environmental

conditions, transport[ed] the same quality crude oil that contributed to the cause of the internal

corrosion in PBWOA, and [were] operated and maintained in a similar manner” (¶ 86).

191. BPXA is liable for the false and misleading statements and omissions by

Defendant Johnson who was Senior Vice President of BPXA.

3. Browne’s False and Misleading Statements and Omissions On Behalf of BP After March 2006 About Corrosion And Efforts To Avoid Another Spill

(a) The Corrosion Monitoring And Leak Detection Systems Were Not World Class And Violated Alaska’s Laws And Regulations

192. On April 25, 2006, the Company conducted a press conference at which Browne

addressed the recent oil spill in Alaska. He claimed that the spill occurred “in spite of the fact

that” BP had a “world class corrosion monitoring system,” and “leak detection system,” as

follows:

As you are aware, in early March we had an oil spill in Alaska from a leak in a 34 inch pipeline which transports oil from one of our production Gathering Centers to the Trans-Alaska Pipeline.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

This spill has now been completely cleaned up.

The leak resulted from a small hole caused by corrosion of the pipeline. This happened in spite of the fact that we have both world class corrosion monitoring and leak detection systems, both being applied within regulations set by the Alaskan authorities.

(i) The Corrosion Monitoring System WasNOT World Class

193. The statement by Browne, that the spill occurred “in spite of the fact that we have

[a] . . . world class corrosion monitoring system,” was false and misleading because,

(a) BPXA’s failure to pig the EOA line establishes that the corrosion

monitoring system was not “world class,” given that, according to,

(i) the Department of Transportation, a failure to pig “does not

represent sound management practices for internal corrosion control” (¶ 76);

(ii) Oregon Representative Greg Walden’s testimony at the

Congressional hearings, “experts to a person have explained pig runs as an essential element of

any sound corrosion control program” (¶ 75); and

(iii) BP America’s then Chairman and President Robert Malone,

Alyeska had a “world class corrosion program . . . with pigging and smart pigging” (¶ 77).

(b) the pipelines at Prudhoe Bay were under-inspected, under-maintained, and


all production at Prudhoe Bay (¶¶ 81-85; 128-157);

(c) BPXA admitted in the Plea Agreement that it “knew that it had

insufficient inspection data on the EOA OTL” (¶¶ 128, 143);

(d) the corrosion monitoring system was in violation of, and not in

compliance with, BPXA’s own Spill Prevention Plan (¶¶ 138-157);

(e) BPXA had severely curtailed its corrosion maintenance and prevention

efforts (¶ 118);

(f) BPXA had been repeatedly warned that its pipelines were severely

corroded (¶ 58);



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

(g) BP and BPXA had been warned that pigging and smart pigging were

necessary to adequately monitor, inspect and maintain the EOA line at Prudhoe Bay (¶¶ 49-57,

81-85); and

(h) despite the repeated warnings of increased corrosion and dangers in not

pigging, BPXA failed to pig the EOA line (¶¶ 100-102, 108).

(ii) The Leak Detection System Was NOT World Class

194. The statement by Browne that the spill occurred “in spite of the fact that we have

[a] . . . world class . . . leak detection system” was false and misleading because,

(a) the leak detection system was in violation of, and not in compliance with,

BPXA’s own Spill Prevention Plan (¶¶ 130-136, 150-157);

(b) pursuant to the CAO, “the leak detection system was not effective in

recognizing and identifying the failure” (¶ 82);

(c) for the leak detection system to function properly it required clean pipes,

free of sediment, and BPXA knew that the OTLs had heavy sediment buildup and not been

pigged in years, and that this impeded the proper functioning of the leak detection system (¶ 43);

(d) operators of the leak detection system regularly disregarded the automatic

meter alarms because they knew that the OT-21 line had high BS&W, which materially

interfered with the proper functioning of the automatic meters (¶ 157); and

(e) the leak detection system was supposed to detect leaks within 12 hours but

failed to detect the March 2006 leak for 5 days (¶ 155).

(iii) The Corrosion Monitoring And Leak Detection Systems Violated Alaska’s Laws And Regulations

195. The statement by Browne that the spill occurred “in spite of the fact that we have

both world class corrosion monitoring and leak detection systems, both being applied within

regulations set by the Alaskan authorities,” was false and misleading because,

(a) the corrosion monitoring and leak detection systems were in violation of,

and not in compliance with, Alaska laws and regulations, as set forth in the Alaska Complaint

(¶¶ 138-157); and



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

(b) the corrosion monitoring and leak detection systems were in violation of,

and not in compliance with, BPXA’s own Spill Prevention Plan, which in itself constituted a

violation of Alaska laws and regulations, as set forth in the Alaska Complaint (¶¶ 138-157).

4. BP’s False And Misleading Statements and Omissions About Compliance With Environmental Laws And Regulations

196. The BP 2005 Annual Report issued on June 30, 2006 stated that:

Management believes that the Group’s activities are in compliance in all material respects with applicable environmental laws and regulations.

197. These statements in the BP 2005 Annual Report were false and misleading

because:

(a) BP had violated the March 15, 2006 CAO by, inter alia, failing to

maintenance and smart pig the EOA transit line (¶ 85);

(b) the Consent Decree established that BPXA had failed to comply with and

violated the CAO requiring BPXA to take additional corrective actions after the March 2006

spill (¶¶ 133-135);

(c) BPXA entered into the Guilty Plea with DOJ in 2007 in which it admitted

that it criminally violated the Clean Water Act in connection with the March and August 2006

spills (¶¶ 127-128);

(d) the corrosion monitoring and leak detection systems were in violation of,

and not in compliance with, Alaska laws and regulations, as set forth in the Alaska Complaint

(¶¶ 138-157); and

(e) the corrosion monitoring and leak detection systems were in violation of,

and not in compliance with, BPXA’s own Spill Prevention Plan, which in itself constituted a

violation of Alaska laws and regulations, as set forth in the Alaska Complaint (¶¶ 138-157).

5. BP’s 2006 False And Misleading Statements and Omissions About Compliance With “Best Environmental Practices”

198. The BP 2005 Annual Report issued on June 30, 2006 also stated that:

BPXA developed and implemented a nationwide environmental management system consistent with the best environmental practices at Group facilities engaged in oil exploration, drilling



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

and/or production in the US and in its territories.

199. The statement that BP implemented and maintained a nationwide environmental

management system in Alaska, “consistent with the best environmental practices,” was

materially false and misleading, for the following reasons:

(a) BPXA entered into a plea agreement with DOJ in 2007 in which it

admitted that it criminally violated the Clean Water Act in connection with the March and

August 2006 spills (¶¶ 127-128);

(b) BPXA’s corrosion monitoring and leak detection system violated and

failed to comply with Alaska State laws and regulations (¶¶ 138-157);

(c) BPXA’s corrosion monitoring and leak detection system violated and

failed to comply with BPXA’s own Spill Prevention Plan (¶¶ 138-157).

(d) the pipelines at Prudhoe Bay were under-inspected, under-maintained, and


all production at Prudhoe Bay (¶¶ 81-85, 128, 136-157);

(e) corrosion maintenance and prevention efforts had been severely curtailed

(¶ 118);

(f) BP and BPXA had been warned that the pipelines were severely corroded,

including BP’s Board of Directors which had received a letter in May 2004 warning “of serious

corrosion problems” and predicting a “major catastrophic event” (¶ 59);

(g) BP and BPXA had been warned that pigging and smart pigging the EOA

line was necessary to adequately monitor, inspect and maintain the pipelines at Prudhoe Bay, and

ensure prevention of another spill (¶¶ 49-57, 81-85); and

(h) despite the repeated warnings of increased corrosion and dangers in not

pigging, BPXA did not pig (¶¶ 100-102, 108).

200. Defendants had actual knowledge of the misrepresentations and omissions of

material facts set forth herein, or acted with deliberate reckless disregard for the truth in that they

failed to ascertain and to disclose such facts and omissions, even though such facts and



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

omissions were available to them. Defendants’ material misrepresentations and/or omissions

were made knowingly or with deliberate recklessness and for the purpose and effect of

concealing the problems at Prudhoe Bay from investors and supporting the artificially inflated

prices of BP’s ordinary shares and ADRs. As demonstrated by Defendants’ misleading

statements and omissions of the operations of Prudhoe Bay throughout the Class Period,

Defendants, if they did not have actual knowledge of the misrepresentations and omissions

alleged, were deliberately reckless in failing to obtain such knowledge by deliberately refraining

from taking those steps necessary to discover whether those statements were false and

misleading.

201. As a result of Defendants’ material omissions and misrepresentations set forth in

this Count, the market price of BP’s ordinary shares and ADRs was artificially inflated during

the Class Period. Unaware of the deceptive and manipulative devices and contrivances

employed by Defendants, Lead Plaintiffs and the Class relied, to their detriment, on the integrity

of the market price in purchasing BP’s ordinary shares and ADRs. Had Lead Plaintiffs and the

Class known the truth, they would not have purchased BP’s ordinary shares and ADRs, or would

not have purchased them at inflated prices.

202. As a direct and proximate cause of Defendants’ wrongful conduct, Lead Plaintiffs

and the Class have suffered an economic loss and damages in an amount to be proved at trial.

203. By reason of the foregoing, Defendants have violated Section 10(b) of the

Exchange Act and Rule 10b-5 promulgated thereunder, and are liable to Lead Plaintiffs and the

Class for damages suffered in connection with the purchases of BP’s ordinary shares and ADRs

during the Class Period.

COUNT II

Violations of § 10(b) of the Exchange Act and Rule 10b-5(a) and (c) Promulgated Thereunder Against BPXA


herein. This Count is asserted against BPXA for violations of Section 10(b) of the Exchange Act

and Rule 10b-5(a) and (c) promulgated thereunder.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

205. During the Class Period, BPXA employed devices, schemes or artifices to defraud

and engaged in acts, practices, or a course of business which operated as a fraud or deceit, which

(a) deceived the investing public, including the Lead Plaintiffs and other members of the Class,

and (b) caused Lead Plaintiffs and other members of the Class to purchase BP’s ordinary shares

and ADRs at inflated prices.

206. BPXA employed devices, schemes, and artifices to defraud and engaged in acts,

practices, and a course of business that operated as a fraud and deceit upon the purchasers of

BP’s ordinary shares and ADRs in an effort to maintain artificially high market prices in

violation of Section 10(b) of the Exchange Act and Rule 10b-5(a) and (c) promulgated

thereunder. Lead Plaintiffs sue BPXA as a primary participant in the wrongful and illegal

conduct charged herein.

207. BPXA directly and indirectly, by the use and means of instrumentalities of

interstate commerce and/or the mails, engaged and participated in a scheme and continuous

course of business whereby “cost-cutting was the emphasis for operation of the Greater Prudhoe

Bay Unit of BPXA for many years without regard for the ever-increasing costs of running an

aging oil field,” which resulted in the Guilty Plea. On October 24, 2007, BPXA pleaded guilty

to a criminal violation of the Clean Water Act in connection with the oil spills at Prudhoe Bay as

set forth in the Guilty Plea. In connection with the Guilty Plea, the United Stated filed a

sentencing memorandum on November 26, 2007, with the United States District Court of Alaska

(the “Sentencing Memorandum”). The Sentencing Memorandum concluded that, “in the view of

the United States, this was a serious environmental crime.” (at 9). “The lasting damage to the

tundra is unknown.” (at 9-10).

208. The Sentencing Memorandum described the scheme and course of conduct of

BPXA.

It is the government’s contention that the failure to adequately manage the corrosion in the pipeline that leaked – in light of the risks known to BPXA – was due to BPXA’s failure to allocate sufficient resources to ensure safe and environmentally protective operation of the pipelines that leaked. Cost-cutting was the emphasis for operation of the Greater Prudhoe Bay Unit of BPXA



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

for many years without regard for the ever-increasing costs of running an aging oil field.

209. The Guilty Plea concluded:

Also in 2005, BPXA was aware of increased corrosion activity at GC2 and the WOA OTL….As a result, BPXA did not expend sufficient resources to address the complex issues of corrosion control in the OTLs

210. The “serious crime” committed by BPXA, and admitted to in the Guilty Plea,

constituted a (i) device, scheme or artifice to defraud, and (ii) acts, practices, or a course of

business which operated as a fraud and deceit upon the purchasers of BP’s ordinary shares and

ADRs. BPXA is liable under this Count for its own conduct, which alone, constituted a (i)

device, scheme or artifice to defraud and (ii) acts, practices or course of business which operated

as a fraud and deceit. BPXA’s own criminal conduct was separate and distinct from any false

statements actionable under Rule 10b-5(b) and encompassed conduct beyond any such

misrepresentations.

211. Lead Plaintiffs and the members of the Class relied on BPXA not to violate the

applicable law and regulations and not to commit a crime. BPXA’s misconduct, deceptive acts,

scheme and course of business were communicated to the public here through the 2006 oil spills

and subsequent shutdown of Prudhoe Bay in August 2006. BPXA’s deceptive scheme and

course of conduct were directly tied to the Guilty Plea, 2006 oil spills, and production shutdown.

The principal purpose and effect of BPXA’s own criminal conduct was to create a false

appearance of fact in furtherance of the scheme and course of business which operated as a

fraud.

212. BPXA acted with the requisite scienter in that BPXA had actual knowledge of the

deceptive device, scheme, practices and course of conduct set forth herein, or acted with

deliberate recklessness.

213. As a result of BPXA’s deceptive scheme and course of conduct the market price

of BP’s ordinary shares and ADRs was artificially inflated during the Class Period. In ignorance

of the fact that the market price of BP’s ordinary shares and ADRs was artificially inflated, and



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

relying directly or indirectly upon the integrity of the market in which BP’s ordinary shares and

ADRs were traded, and/or on the absence of material adverse information that was known or

with deliberate recklessness disregarded by BPXA but not disclosed in public statements during

the Class Period, Lead Plaintiffs and the other members of the Class acquired BP’s ordinary

shares and ADRs during the Class Period at artificially inflated prices and were damaged

thereby.

214. By virtue of the foregoing, BPXA has violated Section 10(b) of the Exchange,

and Rule 10b-5(a) and (c) promulgated thereunder.

215. As a direct and proximate cause of BPXA’s wrongful conduct, Lead Plaintiffs and

the other members of the Class suffered damages in connection with their purchases of BP’s

ordinary shares and ADRs.

COUNT III

Violations of § 20(a) of the Exchange ActAgainst BP, Browne, and Johnson


herein. This Count is asserted for violations of Section 20(a) of the Exchange Act against all

Defendants except BPXA.

217. Defendant Browne was Chief Executive of BP during the Class Period, and acted

as a controlling person of BP and BPXA within the meaning of Section 20(a) of the Exchange

Act, as alleged herein. By virtue of Defendant Browne’s executive position, Defendant Browne

had the power to influence and control, and did influence and control, directly or indirectly, the

statements and/or omissions of BP and BPXA, including the content and dissemination of the

various statements which Lead Plaintiffs contend are false and misleading.

218. Defendant Johnson was BPXA’s Senior Vice President of the Greater Prudhoe

Bay Unit during the Class Period. As Senior Vice President of BPXA, Defendant Johnson was

responsible for the information provided by BPXA to the public, and acted as a controlling

person of BPXA within the meaning of Section 20(a) of the Exchange Act, as alleged herein. By

virtue of Defendant Johnson’s executive position, Defendant Johnson had the power to influence



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

and control, and did influence and control, directly or indirectly, the statements and/or omissions

of BPXA, including the content and dissemination of the various statements which Lead

Plaintiffs contend are false and misleading.

219. BPXA was a wholly-owned subsidiary of BP during the Class Period. BP acted

as a controlling person of BPXA within the meaning of Section 20(a) of the Exchange Act, as

alleged herein. By virtue of BP’s ownership of BPXA, BP had the power to influence and

control, and did influence and control, directly or indirectly, the statements and/or omissions of

BPXA, including the content and dissemination of the various statements which Lead Plaintiffs

contend are false and misleading.

220. In addition, BP’s agreement with BPXA to the terms of the Support Agreement,

in which BP agreed to “cause [BPXA] to perform its payment obligations” to the BP Prudhoe

Bay Royalty Trust, and accept BPXA’s obligations to the BP Prudhoe Bay Royalty Trust in

certain circumstances, further demonstrates that BP is a controlling person of BPXA.

221. The primary and controlling person liability of the Individual Defendants named

in this count also arises from the following facts: (i) each of the Individual Defendants named in

this count had direct involvement in the day-to-day operations of the Corporate Defendants and

therefore, is presumed to have had the power (and exercised same) to control or influence the

particular events and occurrences giving rise to the securities violations as alleged herein,

especially by virtue of their senior positions; (ii) the Individual Defendants named in this count

were high-level executives of the Corporate Defendants during the Class Period and were

members of the Corporate Defendants’ management team; (iii) by virtue of their responsibilities

and activities as senior executives of the Corporate Defendants, the Individual Defendants named

in this count were privy to and participated in the drafting, reviewing, approving the misleading

statements, releases, reports, and other public representations of and about the Corporate

Defendants’ business and operations, and, in particular, about the operation and outlook of

Prudhoe Bay and the condition and maintenance of the pipeline; (iv) the Individual Defendants

named in this Count knew or had access to the material adverse non-public information about the



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

Corporate Defendants’ business and operations, including the operations and corrosion

maintenance and monitoring program at Prudhoe Bay and, in particular, about the condition and

maintenance of the pipelines; and (v) the Individual Defendants named in this count were aware

of the Corporate Defendants’ dissemination of information to the investing public which they

knew, or with deliberate recklessness disregarded, was materially false of misleading.

222. As set forth above, BP and the Individual Defendants named in this count violated

Section 10(b) of the Exchange Act and Rule 10b-5 by their acts and omissions as alleged-herein.

By virtue of their positions as controlling persons of BP or BPXA, each of the Defendants named

in this count is liable pursuant to §20(a) of the Exchange Act.

223. As a direct and proximate result of the wrongful conduct, Lead Plaintiffs and the

Class suffered an economic loss and damages in connection with their purchases of BP’s

ordinary shares and ADRs during the Class Period in an amount to be proved at trial.

JURY DEMAND

Lead Plaintiffs hereby demand a trial by jury as to all issues.

WHEREFORE, Lead Plaintiffs respectfully request that the Court enter judgment in

favor of the Lead Plaintiffs and the Class as follows:

A. Determining that the instant action is a proper class action maintainable under

Rule 23 of the Federal Rules of Civil Procedure;

B. Awarding compensatory damages, jointly and severally against all defendants,

including losses on August 7 and 8, 2006, and thereafter;

C. Awarding interest on the foregoing amounts as allowed by law;

D. Awarding attorneys’ fees and the costs and disbursements of this action;

E. Granting such other and further relief as the court may deem just and proper,

including injunctive relief concerning any serious conduct that impacts the environment.



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

Dated: October 14, 2011

s/ Javier BleichmarThomas A. Dubbs (admitted pro hac vice)Javier Bleichmar (admitted pro hac vice)Erin H. Rump (admitted pro hac vice)LABATON SUCHAROW LLP140 BroadwayNew York, NY 10005212-907-0700 (tel)212-818-0477 (fax)[email protected]@[email protected]

Robert D. Stewart, WSBA #8998Timothy M. Moran, WSBA #24925KIPLING LAW GROUP PLLC3601 Fremont Avenue N., Suite 414Seattle, WA 98103206.545.0345 (tel)206.545.0350 (fax)[email protected]@kiplinglawgroup.com

Counsel for Lead Plaintiffs

OF COUNSEL:

GLANCY BINKOW & GOLDBERG LLPPeter A. BinkowNeal A. Dublinsky(Admitted pro hac vice)1801 Avenue of the Stars, Suite 311Los Angeles, CA 90067Tel.: (310) 201-9150Fax: (310) 201-9160



1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

CERTIFICATE OF SERVICE

I hereby certify that on the 14th day of October, 2011, I electronically filed the foregoing

with the Clerk of the Court using the CM/ECF system which will send notification of such filing

to the following:

Peter A Binkow [email protected]

Javier Bleichmar [email protected]

Thomas A Dubbs [email protected]

Neal A Dublinsky [email protected]

Elizabeth K Ehrlich [email protected]

Jonathan Gardner [email protected]@labaton.com

David C Lundsgaard [email protected]@grahamdunn.com

Diane L McGimsey [email protected]&[email protected]

Timothy Michael Moran [email protected]@kiplinglawgroup.com

Richard C Pepperman, [email protected]

Steven J Purcell [email protected]

Erin H. Rump [email protected]@labaton.com

Robert D Stewart [email protected]

Stefanie J Sundel [email protected]

John L Warden [email protected]@sullcrom.com

DATED this 14th day of October, 2011.

s/ Javier BleichmarThomas A. Dubbs (admitted pro hac vice)Javier Bleichmar (admitted pro hac vice)Erin H. Rump (admitted pro hac vice)LABATON SUCHAROW LLP140 BroadwayNew York, NY 10005212-907-0700 (tel)212-818-0477 (fax)[email protected]@[email protected]


Exhibit 1


EXPERT REPORT OF DR. JOHN S. SMART III ALLOWABLE CORROSION RATES AND PREDICTED LIFETIMES IN OIL PIPELINE

This report discusses the high rate of internal corrosion experienced by BP Exploration Alaska, Inc. (BPXA) on its Oil Transit Line 21 leading up the March 2006 release from that line. Those internal corrosion rates and the likely causes for the apparent rapid increase in those rates are compared to corrosion rates normally expected in crude oil pipelines. Engineering calculations to determine pipeline expected corrosion rates are demonstrated and examples based on allowable corrosion rates over the service life of a pipeline are contained in this report. These allowable corrosion rates determine the maximum permissible corrosion that can be tolerated in a pipeline during its operation, since... Pipelines are normally designed with only a nominal corrosion allowance, such as 1/16 inch (0.0625 inches).

In preparing this report I have depended on my 39 years as a metallurgist and corrosion engineer specializing in oil and gas production, pipelines, ships, refineries and chemical plants, accepted engineering standards and corrosion control practices. My CV is attached to this report.

In their analysis of the pipeline failures, BPXA issued a number of reports including two reports:

1. GC-2 TRANSIT LINE SPILL Prudhoe Bay Western Operating Area, March 2, 2006 INCIDENT INVESTIGATION REPORT, March 31, 2006, and

2. FS-2 OIL TRANSIT LINE PRUDHOE BAY EASTERN OPERATING AREA, AUGUST 6, 2007 INCIDENT INVESTIGATION REPORT JANUARY 31, 2007

The second report concerned a second spill discovered during the phased shut-down of the Prudhoe Field following the discovery of unexpected severe corrosion and a spill in the Eastern Operating Area. The analysis of the corrosion rates found and the reasons for the corrosion are taken mainly from the first of these reports.

Control and Monitoring of Pipeline Corrosion

Corrosion in pipelines can only occur when the wall of the pipe becomes wet with water, since all pipeline corrosion is electrochemical in nature, requiring an electrolyte such as water to be present. In oil pipelines carrying sales quality oil with only 0.35% water, one might assume that corrosion would not occur under these conditions. This is not true, however, since water can settle to the bottom of a pipeline and collect in low spots if the oil velocity is not high enough. For a 34 inch pipeline, the oil velocity in the line pipe must be at least 2.3 ft/sec according to the calculation method of Wicks (Ref. M. Wicks and J. Fraser, “Entrainment Velocity for Water in Flowing Oil,” Materials Performance, May 1975 ), or 215,000 BOPD in this line to be able to sweep water uphill and through to the end of the line. At lower flow rates, water will stratify and collect in the bottom of the line, permitting corrosion to occur.

Corrosion inhibitors can and should be used to control the corrosion rate to low values and permit the continued long term use of the line. Corrosion inhibitors are chemicals added in small quantities that interfere with the chemical reaction of corrosion. One way in which they function is to keep the wall of the pipe in an oil wet condition, preventing contact with water. Corrosion inhibitors can reduce corrosion rates by more than 95% if they are used correctly. When bacteria


are involved in the corrosion reaction, corrosion inhibitors effective against bacteria or biocides can also be used, greatly reducing the ability of bacteria to thrive in the pipeline water or possibly killing them. If corrosion inhibitors and biocides are needed to control MIC, then they must be run in conjunction with a conventional pig equipped with wire brushes than can scratch through the layer of slime covering bacteria deposits and allow the chemical to reach the bacteria underneath. Without pigging, up to ten times the concentration of chemical is required to gain control of the bacteria in the pipeline..

Corrosion caused by bacteria can occur at very high rates, as much as 120-160 mils per year or more in un-treated or ineffectively treated pipelines. This high rate was certainly possible in this pipeline as the temperature of about 110oF is ideal for the growth of bacteria and there is an unlimited supply of low molecular weight hydrocarbon nutrients available in this line. If the corrosion rate were discovered to be 32 mpy by a monitoring program, then BPXA should have known that their chemical treating program was ineffective and that remaining life of the line was short

If a MIC corrosion rate of 30 mils per year were postulated, and that MIC corrosion began when the velocity of the line became low enough for water to collect in low spots in the line, approximately mid-1994, then the line could be expected to leak after about 12 years, or in 2006 based on the original wall thickness of the pipe If the corrosion rates were typical of untreated MIC at 120 mils per year, then corrosion would have penetrated the original wall of the pipe in only three years.

Keeping the pipeline clean is of great importance, as sediments can accumulate in the bottom of a pipeline. Sediments are typically corrosion products such as iron carbonate, iron oxide or possibly iron sulfide, and sand if sand is produced in the wells. These sediments can provide a home for bacteria which can thrive in the pore spaces in the sediment and cause corrosion. Pipelines are cleaned using pigs, or mechanical scrapers that are propelled through the line by the flowing oil. The pigs scrape off deposits on the walls of the pipe and push the deposits through to the end of the line. In almost all cases, the velocity required to push sediments through a pipeline is about 8 - 10 feet per second, a higher velocity than found in most pipelines, thus requiring pigs to clean the line.

Permissible Corrosion Rates

The amount of corrosion that can be tolerated by a pipeline can be determined for two different types of corrosion: general or uniform corrosion, and pitting corrosion. In the first type, if uniform corrosion occurs, or similarly, a groove is corroded in a line along the bottom of the pipe, the amount of corrosion that can be allowed to occur during the life of the pipeline is determined by how thick the remaining wall of the pipe must be to hold the internal pressure in the pipe before bursting. This can be considered as the amount of corrosion that can occur before burst, or the corrosion allowance. The corrosion rate that can be tolerated in the pipe is then simply the corrosion allowance divided by the service life of the pipe. For instance, if a pipe has 0.375 inches wall thickness and requires 0.125 inches to hold the pressure, the amount of metal that can be lost before burst is 0.250 inches.

The other situation is if pitting corrosion occurs, that is, the corrosion forms small holes in the wall of the pipe. In this case, the pressure in the pipe is held by the un-corroded part of the pipe until the corrosion pit penetrates nearly completely through the pipe causing a pin-hole leak. With a corrosion rate of 32 mils per year (mpy) as reported in the subject report, OT-21 would be


completely penetrated by pitting corrosion in about 12 years based on the full thickness of the pipe. This is much too high a corrosion rate to provide adequate and safe service from this pipeline, which could only tolerate a corrosion rate of a few mils per year depending on the projected service life of the pipeline.

In summary,

(a) it is apparent that corrosion had been occurring at a high rate in the OT – 21 line and had been seriously mismanaged by BP based on the following points:

1. The on-set of corrosion due to water stratification in the pipeline apparently was never considered as part of their corrosion analysis;

2. The corrosion inhibitor program in the field did not control the corrosion in the pipeline;

3. Corrosion monitoring depended on spot checks using Ultrasonic Thickness testing where they could get to it, and did not focus on the most likely internal corrosion locations.

4. In-Line Inspections using instrumented pigs, a technology which was well developed at the time of the leaks, and which could have detected the corrosion over 100% of the pipe wall, were not run.

(b) the corrosion was not manageable due to the failure to maintenance pig.


1

Dr. John S. Smart, III 542 Stoneleigh Drive Houston, TX 77079 tel 281 493 5946 cell 832 656 5946 fax 281 493 5024 email: [email protected]

RESUMĒ SUMMARY John S. "Jack" Smart is President of John Smart Consulting Engineers, an independent Consulting Engineering Company in the areas of corrosion, pipelines, metallurgy and training, and partner in DYNAMIC MONITORING SYSTEMS, INC. He has 38 years experience as a corrosion engineer, metallurgist and operations engineer with The International Nickel Company, Amoco Corporation and as a corrosion consultant. He has extensive practical field experience in all phases of oilfield corrosion control, including refineries and petrochemical plants, gas plants, drilling, oil and gas production, internal and external corrosion of pipelines, intelligent pig interpretation including B31G/RSTREN analysis, cathodic protection, materials selection, offshore platform corrosion design and inspection programs, Risk Based Inspection, coatings, chemical treating of oil and gas, and water treating for waterflooding and disposal. He is known for his practical and cost effective solutions to corrosion problems. EDUCATION B.E. Chemical Engineering, Yale University, 1963 Ph. D. Materials Science, Northwestern University 1968. University of Chicago Business School evening program, completed course requirements for majors in Accounting, Finance and International Business, did not graduate due to travel requirements for job. Continuing Education: Corrosion and Water Treating, Internal Corrosion in Pipelines, Economics for Engineers, Gas Well Operations, Sour Gas Handling, Multi-Phase Flow, Pressure Transient Analysis, Fracture Mechanics, Design Elements of Offshore Structures, Quality Process, Managing Negotiations, Strategic Planning, Microbiology WORK HISTORY John Smart Consulting Engineers, Principal, 1991- present

• Corrosion consulting to the oil and gas production, pipeline and marine transportation industries • Packer Engineering, Naperville, IL, consultant

Amoco Chemical Co. Welchem Division, Houston, TX 1987-1991 Manager, International Sales Consulting Engineer, pipelines Amoco Production Company, Houston, TX 1983-1987 Consulting Engineer - Corrosion in Oil and Gas Production and Pipelines, Water Treating for Water

Flooding. Directly responsible for all Amoco Production corrosion control programs in Argentina, Trinidad,


2

UK, Norway, Netherlands, Egypt, UAE, including training of nationals. Amoco Trinidad Oil Company, Galeota Point, Trinidad, West Indies. Engineering Group Supervisor-Production

Facilities, 1980-1982; 1 yr. Assignment in Petroleum Engineering (1982-1983) Amoco International Oil Company, Chicago Illinois 1973-1980 Sr. Staff Engineer, Corrosion. Had responsibility for all corrosion control programs in Amoco International Oil Co. operations in Argentina, Venezuela, Trinidad, UK, Netherlands, Norway, Egypt, Iran Amoco Oil Company, Whiting, Indiana Research Laboratories, Research Project Engineer - Metallurgy and Corrosion, 1970-1973; Refineries and Petrochemical Plants Assistant to President, Martin Oil Service, 1968-1970 Research Metallurgist, The International Nickel Company Research Laboratories, Suffern N.Y. (1967-1968) PROFESSIONAL AFFILIATIONS AND OFFICES HELD 1. Member, NACE (39 yrs), AIChE (15 yrs), SPE (35 yrs) 2. Past Chairman, NACE Houston Section, 1989-1990, Program Chairman 1991-1994, 2000-2003 3. Active member of NACE Technical Committees in T-1 (Oil and Gas Production), T-3 (Corrosion Science and Technology), T-6 (Coatings), T-7 Cathodic Protection, and T-10 (Underground Corrosion Control). -Past Chairman: NACE T-10E-4 "Internal Corrosion in Pipelines" -Past Chairman: NACE T-1-4 committee on "Erosion Corrosion in Oil and Gas Production". -Past Chairman: T-1C-17 "Predicting Environmental Aggressiveness of Oilfield Systems from System Conditions" 5. Member: API RP-14E re-write Committee on "Design and Installation of Surface Production Equipment on Offshore Platforms." 1994-1995 6. Board of Directors, The Offshore Technology Conference, 1989-1995 representing AIChE 7. Program Committee of Offshore Technology Conference, 12 times symposium chairman. 8. Technical Paper Reviewer for SPE, NACE 9. Gas Research Institute Microbiological Corrosion Users Group 10. Technical Activities Committee Chairman, Pigging Products and Services Association 11. Member, NACE Materials Performance magazine, Editorial Advisory Board, 1999-2009 12. Pipeline Integrity Management Magazine (UK) Editorial Board, 2001-2009 WORK EXPERIENCES 3 years as Research Project Engineer in Refineries and Petrochemical Plants, plus 14 years as Sr Staff Engineer/Engineering Associate, Corrosion, for Amoco International Oil Company, supervising programs in 10 countries involving extensive travel, field work, and training. 3 years as Engineering Supervisor, Amoco Trinidad Oil Company, 11 years consulting engineer in corrosion of O&G Production, pipelines, marine transportation. The following list is of projects by Dr. Smart: CORROSION CONTROL IN OIL AND GAS PRODUCTION Annual corrosion surveys for Amoco's International Oil and Gas Production Facilities for the periods 1973-1980 and 1984-1987. Responsible for chemical treating, water treating for water flooding, platform Cathodic Protection and inspection, well casing CP, Atmospheric and Pipeline Coatings, corrosion monitoring and life prediction, platform inspection, economic evaluation for corrosion control investments. Extensive International travel and supervision of local corrosion control efforts.


3

Consultancy Projects 1. Materials specifications for sour gas production wells, process and plant equipment, and pipelines. 2. Corrosion monitoring systems for sour gas production system, salt dome brine mining system 3. Corrosion design for several offshore oil and gas fields with high carbon dioxide content. 4. Corrosion control in high rate high H2S well test with carbon steel tubulars. 5. Materials and corrosion specifications for Floating Production System and pipeline. 6. Coiled tubing inhibitor distribution system for unmanned offshore platforms. 7. Inspection of oil and gas production system with corroded welds, surface process equipment and underwater

pipeline system, including development of UT inspection specifications of welds based upon fracture mechanics. 8. Downhole chemical injection for corrosion, paraffins and emulsions in gas lift oil wells. 9. Storage tank bottoms chemical treating program (Corrosion Inhibitors and Biocides). 10. Course in "Oil Field Metallurgy" for field operators and engineers of major oil company. 11. Corrosion design of four Tension Leg Platforms in Gulf of Mexico 12. Total Corrosion Design of 4 platform Dong Fang Gas Field, China National Offshore Oil Co 13. Corrosion Control in Salt Dome brine mining system and brine pipeline 14. Corrosion design for three offshore gas fields in Asia, including in-field pipelines 15. Corrosion control design for over 15 gas compression systems 16. Evaluation of Pipelines by ASME B31G and RSTRENG for Mechanical Integrity 17. Interpretation of Intelligent Pig results for offshore and onshore pipelines 18. Cathodic Protection design of 7 pipelines, including chemical lines 19. Analysis of HVAC Interference of over 10 Pipelines 20. Drying of Pipelines after hydrotest for sour service 21. Evaluation of 36” offshore pipeline from intelligent pig inspection results for prospective purchaser 22. Course in Internal Corrosion of Pipelines to two major oil companies 23. Risk analysis for corrosion for Oman India Pipeline 24. Evaluation of trans-Andean oil pipeline for mechanical integrity, corrosion 25. Analysis of MIC in oil production equipment 26. Specification of properties and testing protocols for chemicals used in deep water production systems 27. Pipeline Risk Management Course for overseas National Oil Company in Asia. 28. Corrosion inhibitors for Cement 29. Pipeline Coating Performance and Cathodic Protection potential attenuation. 30. Hydraulic Fluid Corrosion problems in heavy construction equipment and tractors 31. Failed 10,000 psi lower master valve on gas well 32. Gel Pigging Dispute for pipeline 33. Risk Based Inspection design for deep water platforms 34. Fitness for purpose analysis of platform process equipment 35. Deep Water platform riser corrosion and corrosion fatigue EXTERNAL CORROSION AND CATHODIC PROTECTION OF PIPELINES 1. Cathodic Protection Surveys of 12 pipelines, over 100 production system gathering lines 2. Cathodic Protection design of 7 pipelines including offshore, onshore, HVAC interference, deep anode bed

design, potential attenuation modelling 3. Offshore Pipeline Riser Splash Zone Coating Repairs 4. Design of an offshore pipeline coating and CP system, 24" Gas Line 5. Retrofit of CP to a Leaking 54 Inch Offshore Tanker Loading Line


4

6. Analysis in Corroded Pipelines per ASME B31G. 7. Corrosion of pipeline and AC Mitigation in HVAC Transmission Line Right of Way (6) 8. CP Interference analysis on oil pipeline 9. Tank Farm Cathodic Protection Systems - analysis and retrofit 10. External MIC on Pipeline Inside Partially Shorted Casing. 11. CP design on Coiled Tubing Flowlines 12. CP Design on Deepwater Field Development for TLP, including piles and tendons, hull 13. NACE Talk: "MIC and Pipelines 14. Corrosion under disbonded coatings on pipelines 15. Cathodic Protection Design on new Pipelines including provision for CP in remote areas 16. External MIC under disbonded pipeline coatings, including expert witness lawsuit experience 17. Deepwater pipeline cathodic protection 18. Developed Finite Element computer program for CP attenuation in pipelines and rectifier spacing INTERNAL CORROSION IN PIPELINES 1. Pipeline On-Line Internal Corrosion and Bacteria Monitoring System 2. 42" Offshore Crude Oil Pipeline System Internal Corrosion Program, including inhibitor program, MFL, and UT

intelligent pig evaluation 3. Failure Analysis in Multi-Products Pipeline due to MIC 4. Chairman: Gulf Coast Corrosion Control Seminar: Internal Corrosion of Pipelines '89-94 5. Internal Sour Gas/Condensate Production Pipeline corrosion program. 6. Carbon Dioxide Gas Gathering System Treatment Program and Analysis 7. Bacteria Corrosion in Pipelines 8. Water, Hydrate and Paraffin Inhibition and Removal from Offshore Pipelines 9. Pigging and Chemical Treating in Pipelines 10. Internal Corrosion Control in a Supercritical Gas Pipeline 11. Internal Corrosion Inspection Program for Offshore Oil Gathering System. 12. PL Company Operating Manual, Sections on Corrosion and Bacteria. 13. Hydrotest Procedures and Regulatory Approvals (Federal and State). 14. Internal Corrosion of PL's Training Program for Major Oil Company. 15. Internal corrosion control and corrosion risk evaluation of Oman-India Pipeline. 16. "MIC of Ships" Talk at SSPC Nat'l Mtg, 1994, to ABS Meeting on Tanker Corrosion, 1995 17. Development of "Pit Cleaning Pig" for bacteria contaminated pipelines. 18. Internal corrosion failure analysis in products pipeline in South America. 19. Internal corrosion analysis for crude oil pipeline with high leak rate. 20. Monitoring and corrosion analysis of salt dome hydrocarbon storage facility, Louisiana 21. Expert witness in two gas pipeline explosion cases 22. Analysis of top of the line corrosion problems in gas pipelines 23. Analysis of black powder problems in gas pipelines 24. Four technical papers on movement of sand and black powder in oil, water and gas in pipelines INTERNAL CORROSION MONITORING IN PIPELINES AND OIL AND GAS PRODUCTION


5

1. Evaluation of Corrosion Inhibitor Programs in high rate gas wells. 2. Evaluation of Chemical Treating in Oil Pipelines for Corrosion and MIC. 3. Inventor - Dynamic Monitoring System - An on-line corrosion and bacteria monitoring system for oil and

gas pipelines 4. "The Galvanic Probe" talk to NACE SC Regional Meeting, 1976 5. "On-Line System Developed for Monitoring Internal Corrosion" Pipe Line and Gas Industry March 1995 6. Evaluation of MIC for External Corrosion of several oil and gas pipelines 7. Designed Corrosion Monitoring System for several major sub-sea pipeline systems 8. Corrosion Monitoring System for Waste Gas Compression System 9. Pipeline condition analysis for pipelines with corrosion, scale and/or paraffins. 10. Computerized analysis of flow hydraulics for corrosion control 11. Salt dome hydrocarbon storage facility brine corrosion monitoring system

OFFSHORE PLATFORM CATHODIC PROTECTION 1. Corrosion Failure of Offshore Platforms Inspection Programs, North Sea, Trinidad 2. Cathodic Protection and Regulatory Inspection of Offshore Platforms 3. Annual CP surveys for over 125 platforms in Middle East, North Sea, Atlantic Ocean 4. Optimized Anode Retrofit Design for Offshore Platforms. 5. Implementation of anode retrofit, saving over $7 million 6. Visual platform surveys using divers and ROVs, damage assessment. 7. Cathodic Protection design of 4 tension leg platforms in Gulf of Mexico in 1600 to 3350 ft water depths. 8. Cathodic protection design of numerous conventional offshore platforms all over the world, including use of

magnesium anodes for high initial polarization designs 9. Cathodic Protection and Anode Specifications for China National Offshore Oil Company Dong Fang Field, 4

platform CP design and inspection program based on high initial polarization design procedure

WATER TREATING FOR WATER FLOODING 1. Water Treating Specifications for seawater water floods and produced water injection. 2. Water Flooding Sate of the Art Manual for major International Oil Company 3. Determination of well plugging and fracturing in water injection wells. 4. Treating for Bacteria in water floods. 5. Monitoring for bacteria and corrosion in seawater water floods. 6. Chlorination specifications and equipment for seawater water floods 7. Deaeration process design in seawater water floods. 8. Scaling of mixed sea-water and formation water in waterfloods. 9. Development of best practices for offshore waterflooding for major international oil company 10. Chemical Treating specifications and quality control for major international oil company

COATINGS 1. Coating Specifications for Maintenance of Offshore Platforms 2. Splash Zone Coating Systems 3. Marine Terminal/Tank Farm Painting Programs 4. Painting of Continuously Wet Piping Systems 5. Roof Painting of Marine Terminal Floating Roof Storage Tanks 6. Fiberglass Storage Tank Bottoms Linings


6

7. Internal Lining of Lease Tanks 8. Coatings Specifications for over 20 offshore platforms including TLP’s, tension legs, drilling semi-submersibles,

and conventional platforms 9. Pipeline coatings specifications including FBE, CTE, syntactic polyurethane foam insulation, hot lines 10. Shielding of pipelines from CP due to disbonded pipeline coatings

REFINERIES AND PETROCHEMICAL PLANTS 1. Hydrogen cracking of welded pressure vessels in a sour gas plant. 2. Materials Specifications for high temperature hydrogen attack of refinery vessel steels using Nelson Curves. 3. Ultraformer explosion failure analysis using fracture mechanics of weld defects 4. Reactor vessel insulation and insulation failure, temperature indicating paints 5. Corrosion of refinery process vessels by organic sulfides and hydrogen sulfide 6. Napthenic acid corrosion of Vacuum Gas Oil vessels by Trinidad crude 7. Corrosion inspection of pipe stills and other refinery process vessels during turn-arounds, including pipe stills. 8. Direct fired furnace tube failures and tube hangers 9. Two stage Desalter operation for corrosion mitigation in pipe stills, demulsifier use and correlation of salt

content to pipe still overhead corrosion problems 10. Pipe still overhead corrosion inhibitor treatments and condenser tube metallurgy 11. Heat exchanger failure analysis and specifications, including titanium tubes in polluted sea water service 12. Numerous refinery failure analysis investigations, including pumps, heater tubes, furnace burner operations 13. Refinery storage tank bottoms corrosion and use of chopped sprayed glass liners 14. Use of stainless steel liner materials in refinery pressure vessels 15. Stress corrosion cracking of stainless steel petrochemical plant piping 16. Hot spot (High Temp) stress analysis in ammonia reactor vessel wall and nozzles 17. HDPE plant debottlenecking assignment, catalyst recovery and product purification 18. Terephthalic acid manufacture vessel corrosion control using titanium and 317L explosion bonded clad steels 19. Refinery and Petrochemical Plants paint testing program 20. Mechanical Integrity and Risk Analysis Program for Refinery in Hawaii OIL TREATING, GAS PLANT CORROSION, ENVIRONMENTAL 1. Oil Process Train Corrosion Analysis, materials specifications for over 10 oil field process plants and gathering

systems 2. Symposium Chairman, "Oily Water Clean-Up" AIChE Nat'l Mtg 1986 3. Project Supervisor - Treatment of Oily Produced Water 4. Sour Gas Plant Corrosion Surveys, 9 plants, US, Middle East, and Canada 5. Corrigated Plate Interceptor analysis for oily water, West Africa offshore platform 6. Landfill Gas Compression with 50% CO2 7. Materials Performance Study for CO2, H2S rejection and recovery by proprietary semi-permeable membrane

process


Exhibit 2


COMPLAINT - Page 1

JOHN C. CRUDENActing Assistant Attorney GeneralUnited States Department of JusticeEnvironment and Natural Resources DivisionKATHERINE A. LOYD1961 Stout St., 8th floorDenver, CO 80294(303) 844-1365(303) 844-1350 (fax)[email protected] for United States of America

IN THE UNITED STATES DISTRICT COURTFOR THE DISTRICT OF ALASKA

______________________________________))

UNITED STATES OF AMERICA, ) )

Plaintiff, ))

v. ) ) Civil No.

BP EXPLORATION (ALASKA) INC., ))) COMPLAINT

Defendant. )______________________________________ )

The United States of America, by authority of the Attorney General of the United States

and through the undersigned attorneys, acting at the request of the Administrator of the United

States Environmental Protection Agency (EPA) and the Secretary of the United States

Department of Transportation, files this Complaint and alleges as follows:

NATURE OF ACTION

1. This is a civil action against BP Exploration (Alaska) Inc. (BPXA) seeking injunctive

relief and an assessment of civil penalties for violations of the Clean Water Act, 33 U.S.C.

§§ 1311, 1319, 1321, as amended by the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq.; the


COMPLAINT - Page 2

Clean Air Act (CAA), 42 U.S.C. §§ 7401-7671q; and the Federal Pipeline Safety Laws, 49

U.S.C. § 60101 et seq. The Clean Water Act claims against BPXA arise from two unauthorized

discharges of crude oil into navigable waters of the United States from BPXA’s pipelines on the

North Slope of Alaska in the spring and summer of 2006, as well as violations of the Spill

Prevention Control and Countermeasure (SPCC) regulations promulgated pursuant to the Clean

Water Act. The Clean Air Act claims against BPXA arise from the improper removal of

asbestos-containing materials from its pipelines in the spring and summer of 2006, in violation of

the National Emission Standards for Hazardous Air Pollutants (NESHAP) for asbestos,

promulgated by EPA under 42 U.S.C. § 7412, and codified at 40 C.F.R. §§ 61.140-61.157. The

Pipeline Safety Law claims arise from BPXA’s failure to comply with an order issued by the

Pipeline and Hazardous Materials Safety Administration of the United States Department of

Transportation (DOT-PHMSA) pursuant to 49 U.S.C. § 60112, requiring BPXA to perform

corrective action on its pipelines.

PARTIES

2. Defendant BPXA is a Delaware corporation with its principal place of business in

Anchorage, Alaska. At all times relevant to this action, Defendant was the operator of the

Greater Prudhoe Bay Unit, Milne Point Unit, and Badami Unit on the North Slope of Alaska.

JURISDICTION AND VENUE

3. This Court has jurisdiction over this matter pursuant to 33 U.S.C. §§ 1319(b) and

1321(b)(7)(E), and (n), 42 U.S.C. § 7413(b), 49 U.S.C. § 60120(a)(1), and 28 U.S.C. §§ 1331,

1345, and 1355.


COMPLAINT - Page 3

4. Notice of commencement of this action has been given to the Director of the Alaska

Department of Environmental Conservation as required by 42 U.S.C. § 7413(b).

5. Venue is proper in this district pursuant to 33 U.S.C. § 1321(b)(7)(E), 42 U.S.C. §

7413(b), and 28 U.S.C. §§ 1391 and 1395 because the violations that are the subject of this

action occurred in this district, and Defendant is located in, does business in, and is found in this

District.

STATUTORY BACKGROUND(CLEAN WATER ACT)

6. The Clean Water Act prohibits the discharge of any pollutant, including oil, by any

person, except as authorized by and in compliance with other sections of the Act. 33 U.S.C. §

1311(a). A “discharge of a pollutant” includes “any addition of any pollutant to navigable

waters from any point source.” 33 U.S.C. § 1362(12). “Navigable waters” are defined as “the

waters of the United States, including the territorial seas.” 33 U.S.C. § 1362(7).

7. The Clean Water Act authorizes the Administrator of the EPA to, inter alia, issue

compliance orders for discharges of pollutants prohibited under 33 U.S.C. § 1311(a). 33 U.S.C.

§ 1319(a). This Act also authorizes the Administrator of the EPA to commence a civil action

for appropriate relief, including a permanent or temporary injunction, for any violation for which

the Administrator is authorized to issue a compliance order under 33 U.S.C. § 1319(a). 33

U.S.C. § 1319(b).

8. The Clean Water Act prohibits the discharge of oil into or upon the navigable waters

of the United States and adjoining shorelines in such quantities as the President determines may

be harmful to the public health or welfare or the environment of the United States. 33 U.S.C. §


COMPLAINT - Page 4

1321(b)(3). This Act defines “discharge” to include “any spilling, leaking, pumping, pouring,

emitting, emptying or dumping . . . .” 33 U.S.C. § 1321(a)(2).

9. Pursuant to 33 U.S.C. § 1321(b)(4), EPA has determined by regulation that the

quantities of oil that may be harmful to the public health or welfare or the environment of the

United States include discharges of oil that violate applicable water quality standards, or cause a

film or sheen upon or discoloration of the surface of the water or adjoining shorelines, or cause a

sludge or emulsion to be deposited beneath the surface of the water or upon adjoining shorelines.

See 40 C.F.R. § 110.3.

10. The Clean Water Act provides that:

(A) Discharge, generally Any person who is the owner, operator, or person in charge of any vessel,

onshore facility, or offshore facility from which oil or a hazardous substance isdischarged in violation of [Section 311(b)(3) of the CWA], shall be subject to a civilpenalty in an amount up to $25,000 per day of violation or an amount up to $1,000per barrel of oil or unit of reportable quantity of hazardous substances discharged.

***

(C) Failure to comply with regulationAny person who fails or refuses to comply with any regulation issued under

subsection (j) of this section shall be subject to a civil penalty in an amount up to$25,000 per day of violation.

(D) Gross negligenceIn any case in which a violation of paragraph (3) was the result of gross

negligence or willful misconduct of a person described in subparagraph (A), theperson shall be subject to a civil penalty of not less than $100,000, and not more than$3,000 per barrel of oil or unit of reportable quantity of hazardous substancedischarged.

33 U.S.C. § 1321(b)(7). The penalty amounts provided for by the Clean Water Act have been

adjusted upwards for inflation by the Federal Civil Penalties Inflation Adjustment Act of 1990 (28

U.S.C. § 2461) and Debt Collection Improvement Act of 1996 (31 U.S.C. § 3701), and 40 C.F.R.

§ 19.4.


COMPLAINT - Page 5

11. The Clean Water Act authorizes EPA to promulgate regulations establishing methods

and procedures for removal of discharged oil, establishing the criteria for the development of oil

and hazardous substance removal contingency plans, and establishing procedures, methods and

equipment to prevent discharges of oil from onshore facilities. 33 U.S.C. § 1311(j). EPA has

promulgated such regulations setting forth what are known as Spill Prevention Control and

Countermeasure requirements, which are codified at 40 C.F.R. Part 112 (SPCC Regulations).

12. The SPCC Regulations apply to owners and operators of non-transportation-related

onshore and offshore facilities engaged in drilling, producing, gathering, storing, processing,

refining, transferring, distributing or consuming oil and oil products, which, due to their location,

could reasonably be expected to discharge oil in harmful quantities into or upon the navigable

waters of the United States or adjoining shorelines. 40 C.F.R. Part 112.

13. Owners and operators of onshore and offshore facilities in operation before January

10, 1974, the effective date of the Oil Pollution Prevention Regulations, had to prepare written

SPCC Plans, in accordance with 40 C.F.R. § 112.7, within six months of the effective date of the

regulations, i.e., by July 10, 1974, and implement those Plans within one year of the effective

date of the regulations, i.e., by January 10, 1975. 40 C.F.R. § 112.3.

14. Owners or operators of facilities that are required to prepare an SPCC Plan are

required to complete a review and evaluation of the SPCC Plan and its implementation at least

once every five years from the date the facility becomes subject to 40 C.F.R. Part 112. See 40

C.F.R. § 112.5(b).

(FEDERAL PIPELINE SAFETY LAWS)

15. Hazardous liquid pipelines were regulated for safety under The Pipeline Safety Act

of 1979, former 49 U.S.C. app. § 1671 et seq. In 1994, Public Law 103-272 repealed this act and


COMPLAINT - Page 6

codified its provisions without substantive change at 49 U.S.C. § 60101 et seq. The Federal

Pipeline Safety Laws, codified at 49 U.S.C. § 60101 et seq., were amended by the Accountable

Pipeline Safety and Partnership Act of 1996. The Pipeline Safety Laws were further amended by

the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection,

Enforcement and Safety Act of 2006.

16. The purpose of the Federal Pipeline Safety Laws “is to provide adequate protection

against risks to life and property posed by pipeline transportation and pipeline facilities by

improving the regulatory and enforcement authority of the Secretary of Transportation.” 49

U.S.C. § 60102 (a) (1).

17. Pursuant to 49 U.S.C. § 60102 (a) (2):

The Secretary shall prescribe minimum safety standards for pipeline facilities.

The standards apply to owners and operators of pipeline facilities; may apply to

the design, installation, inspection, emergency plans and procedures, testing,

construction, extension, operation, replacement, and maintenance of pipeline

facilities; and shall include a requirement that all individuals who operate and

maintain pipeline facilities shall be qualified to operate and maintain the pipeline

facilities.

18. The Pipeline Safety Laws authorize the Secretary of Transportation to, inter alia,

issue corrective action orders if a pipeline facility is or would be hazardous. 49 U.S.C. § 60112.

19. Pursuant to 49 U.S.C. § 60112:

(a) General Authority.— After notice and an opportunity for a hearing, the

Secretary of Transportation may decide that a pipeline facility is hazardous if the

Secretary decides that—

(1) operation of the facility is or would be hazardous to life, property, or the

environment . . .

***

(d) Corrective Action Orders.—


COMPLAINT - Page 7

(1) In general.— If the Secretary decides under subsection (a) of this section that

a pipeline facility is or would be hazardous, the Secretary shall order the operator

of the facility to take necessary corrective action, including suspended or

restricted use of the facility, physical inspection, testing, repair, replacement, or

other appropriate action.

20. Pursuant to these statutory authorities, DOT-PHMSA promulgated Pipeline Safety

Regulations. Those regulations are set forth at Title 49, Parts 190-195 and Part 199. Part 195

provides minimum federal safety standards for the transportation of hazardous liquid and carbon

dioxide by pipeline.

21. Pursuant to 49 U.S.C. § 60101(a)(5), “hazardous liquid pipeline facility” includes a

pipeline, right of way, a facility, a building or equipment used or intended to be used in

transporting hazardous liquid.

22. Pursuant to 49 U.S.C. § 60120, the Secretary of Transportation may bring a civil

action in an appropriate district court of the United States to enforce this chapter, including

section 60112, or a regulation prescribed or order issued under this chapter. The court may

award appropriate relief, including a temporary or permanent injunction, punitive damages, and

assessment of civil penalties, considering the same factors as prescribed for the Secretary in an

administrative case under section 60122.

23. Authority to bring this action is vested in the United States Department of Justice

under 49 U.S.C. § 60120(a)(1), and 28 U.S.C. §§ 516 and 519.

(CLEAN AIR ACT)

24. The Clean Air Act authorizes EPA to identify air pollutants determined to be

hazardous and to prescribe emissions standards for those pollutants. These standards are known

as the National Emission Standards for Hazardous Air Pollutants (NESHAP). 42 U.S.C. § 7412.


COMPLAINT - Page 8

25. EPA has listed asbestos as a hazardous air pollutant under the authority of 42 U.S.C.

§ 7412(b), and has also adopted an asbestos NESHAP which includes regulations governing the

emission, handling, and disposal of asbestos during renovation of asbestos-containing facilities.

These regulations are codified at 40 C.F.R. §§ 61.140-61.157.

26. The Clean Air Act prohibits the operation of any stationary source in violation of an

applicable NESHAP standard. 42 U.S.C. § 7412(i)(3)

27. The Clean Air Act authorizes the United States to commence actions for injunctive

relief and/or civil penalties for violation of, among other provisions, violations of the asbestos

NESHAP. 42 U.S.C. § 7413(b). That authority is retained despite any delegations to states.

See 42 U.S.C. § 7412(l)(7).

FACTUAL ALLEGATIONS

28. BPXA is a “person” within the meaning of 33 U.S.C. § 1362(5) and 42 U.S.C. §

7602(e). BPXA is also an owner or operator of a stationary source and a renovation activity

within the meaning of 42 U.S.C. § 7412(a)(3) and (9), and 40 C.F.R. §§ 61.02 and 61.141.

29. This action is preceded by a criminal case against BPXA. The Plea Agreement,

reached in that case, Crim. No. 3:07-cr-00125-TMB (D. Alaska), and entered on November 29,

2007, states: “BPXA agrees to plead guilty to a one-count information charging BPXA with a

violation of the Clean Water Act, 33 U.S.C. §§ 1319(c)(1), 1321(b)(3), for the negligent

discharge of a harmful quantity of oil to a water of the United States.”

30. Beginning on or about March 1 and lasting through March 6, 2006, a discharge of oil

occurred from the oil transit lines near gathering center 2 (GC-2 ) in the Greater Prudhoe Bay

Unit. An estimated 212,252 gallons of oil spread over approximately two acres of tundra

wetlands and a frozen lake, known as Q-Pad Lake, before BPXA noticed and stopped the leak.


COMPLAINT - Page 9

31. On August 6, 2006, a discharge of oil totaling approximately 1,000 gallons occurred

from the oil transit line between flow stations 1 and 2 in the Greater Prudhoe Bay Unit. The oil

flowed to wetlands and adjacent shorelines.

32. The Plea Agreement contains factual information regarding the spills alleged in this

Complaint and is attached as Exhibit A. The elements of the misdemeanor charge relating to the

March 2006 leak to which BPXA pled guilty are as follows: “(1) the defendant discharged oil

from a point source; (2) the amount of oil discharged was a quantity deemed to be harmful by

federal regulation; (3) the oil was discharged in waters of the United States; and (4) the

discharge was caused by the negligence of the defendant.” Id.

33. The March 2006 leak caused sheens to appear on Q-Pad lake and wetlands adjacent

to the Beaufort Sea and the Kuparuk River, and the August 2006 leak caused sheens to appear in

the wetlands adjacent to the Beaufort Sea and the Sagavanirktok River. Both the March 2006

leak and the August 2006 leak discolored the surface of those waters, wetlands, and the

adjoining shorelines.

34. Q-Pad Lake, the Sagavanirktok River, the Kuparuk River, the Beaufort Sea, the

unnamed tributaries of those bodies of water, and the wetlands adjacent to those bodies of water,

into and onto which BPXA discharged oil, constitute “navigable waters of the United States”

within the meaning of Sections 311(b)(3) and 502(7) of the CWA.

35. Crude oil is “oil” within the meaning of Section 311(b)(3) of the CWA.

36. The oil transit lines located in the Greater Prudhoe Bay Unit are at least one “onshore

facility” within the meaning of Section 311(b)(7) of the CWA.

37. The oil transit lines located in the Greater Prudhoe Bay Unit are at least one “point

source” within the meaning of Section 502(14) of the CWA.


COMPLAINT - Page 10

38. BPXA is engaged in producing, gathering, storing, processing, refining, transferring,

distributing or consuming oil or oil products at the Greater Prudhoe Bay Unit, Milne Point Unit,

and Badami Unit Facilities, as defined in 33 U.S.C. § 1321(a)(1), and 40 C.F.R. §§ 112.1 and

112.2.

39. At all relevant times, BPXA owned and operated the Greater Prudhoe Bay Unit,

Milne Point Unit, and Badami Unit facilities. The Greater Prudhoe Bay Unit, Milne Point Unit,

and Badami Unit Facilities are each an “onshore facility” within the meaning of 33 U.S.C. §

1321(a)(10), and 40 C.F.R. § 112.2.

40. The Greater Prudhoe Bay Unit has the capacity to store approximately 18,789,158

gallons of petroleum products in aboveground storage tanks. The Milne Point Unit has the

capacity to store approximately 2,682,924 gallons of petroleum products in aboveground storage

tanks. The Badami Unit has the capacity to store approximately 764,148 gallons of petroleum

products in aboveground storage tanks.

41. The storm water from the Greater Prudhoe Bay Unit, Milne Point Unit, and Badami

Unit Facilities drains into the Putuligayuk River, the Kuparuk River, the Sagavanirktok River,

the unnamed tributaries of those bodies of water, the wetlands adjacent to those bodies of water,

and the Beaufort Sea. The Putuligayuk River, the Kuparuk River, the Sagavanirktok River, the

Beaufort Sea, and the wetlands adjacent to those bodies of water are “navigable waters” within

the meaning of 33 U.S.C. § 1362(7).

42. Due to their locations, in the event of a discharge of oil, the Greater Prudhoe Bay

Unit, Milne Point Unit, and Badami Unit facilities could reasonably be expected to discharge oil

in harmful quantities, as defined by 40 C.F.R. Part 110, into or on a navigable water of the

United States or its adjoining shorelines.


COMPLAINT - Page 11

43. According to BPXA’s SPCC plan, the Greater Prudhoe Bay Unit, Milne Point Unit,

and Badami Unit facilities are located “at a distance…such that a discharge from the facility

could cause injury to fish and wildlife and sensitive environments.” The facilities are subject to

facility response plan regulations, codified at 40 C.F.R. §§ 112.20 and 112.21, including

Appendices B through F.

44. In an inspection conducted on or about September 24, 2007 through September 28,

2007, EPA ascertained that BPXA had failed to prepare and implement an SPCC Plan in

accordance with good engineering practices and had failed to implement certain required spill

prevention measures, in violation of 40 C.F.R. §§ 112.3 and 112.7.

45. BPXA transports hazardous liquid through pipelines it operates in the state of

Alaska.

46. BPXA is subject to the Federal Pipeline Safety Laws, 49 U.S.C. § 60101 et seq.

Portions of its operations are also subject to the regulations for the transportation of hazardous

liquids and carbon dioxide by pipeline in 49 C.F.R. Part 195.

47. BPXA is a “person” as defined in 49 U.S.C. § 60101 and 49 C.F.R. § 195.2.

48. On March 15, 2006, the Associate Administrator for Pipeline Safety of DOT-

PHMSA issued a Corrective Action Order, CPF No. 5-2006-5015H (Order), pursuant to 49

U.S.C. §60112, to BPXA.

49. The Order required BPXA to take corrective action to protect the public, property

and the environment from hazards associated with a failure discovered March 3, 2006, involving

the pipelines operated by BPXA in Greater Prudhoe Bay, Alaska.

50. DOT-PHMSA amended the Order on July 20, 2006, August 10, 2006, and April 27,

2007. Upon BPXA’s request, DOT-PHMSA extended some deadlines under the Order.


COMPLAINT - Page 12

51. BPXA is currently subject to the Order’s requirements.

52. Beginning in early March 2006 and continuing until August 21, 2006, Defendant

BPXA removed external insulation from oil transit lines in the Greater Prudhoe Bay Unit, in

preparation for pipeline inspection activities.

53. Beginning in March and lasting through at least August of 2006, BPXA unlawfully

removed regulated asbestos-containing material, as detailed below, from the oil transit lines

located in the Greater Prudhoe Bay Unit.

54. The Greater Prudhoe Bay Unit is a “facility” within the meaning of 40 C.F.R. §

61.141.

55. The oil transit lines located in the Greater Prudhoe Bay Unit are “facility

components” within the meaning of 40 C.F.R. § 61.141.

56. The combined amount of regulated asbestos-containing material that was stripped,

removed, dislodged, cut, drilled, or similarly disturbed during the Greater Prudhoe Bay Unit

renovation operation between early March 2006 and August 21, 2006, was in excess of 15

square meters (160 square feet) on facility components or in excess of 80 linear meters (260

linear feet) on pipes and was therefore subject to the asbestos NESHAP work practice

requirements.

57. The facility which was the subject of renovation contained quantities of regulated

asbestos-containing materials in excess of 15 square meters (160 square feet) on facility

components or in excess of 80 linear meters (260 linear feet) on pipes and was therefore subject

to the asbestos NESHAP work practice requirements.


COMPLAINT - Page 13

58. BPXA is subject to the NESHAP regulations because it “owned” or “operated” a

renovation operation at which the threshold amount of regulated asbestos-containing material

was stripped, removed, dislodged, cut, drilled, or similarly disturbed during the renovation.

59. BPXA failed to conduct a survey of the facility or part of the facility where the

renovation operation occurred for the presence of asbestos before beginning the renovation as

required by 40 C.F.R. § 61.145(a).

60. BPXA failed to provide written notification at least 10 working days prior to

beginning asbestos stripping or removal work in March 2006 as required by 40 C.F.R.

§ 61.145(b).

61. BPXA failed to adequately wet regulated asbestos-containing material that was being

stripped from facility components as required by 40 C.F.R. § 61.145(c)(3).

62. BPXA failed to adequately wet regulated asbestos-containing material that had been

stripped from facility components and ensure that it remained wet until collected and contained

or treated in preparation for disposal as required by 40 C.F.R. § 61.145(c)(6)(i).

63. BPXA failed to have an on-site representative who was trained in proper removal of

regulated asbestos-containing material present while regulated asbestos-containing material was

being stripped, removed or otherwise handled or disturbed, as required by 40 C.F.R.

§ 61.145(c)(8).

64. BPXA failed to mark vehicles used to transport asbestos-containing waste material

during the loading and unloading of waste as required by 40 C.F.R. §§ 61.149(d)(1) and

61.150(c).

65. BPXA failed to dispose of all asbestos-containing waste material at a waste disposal

site operated in accordance with 40 C.F.R. § 61.154, as required by 40 C.F.R. § 61.150(b)(1).


COMPLAINT - Page 14

66. BPXA failed to maintain waste shipment records for all asbestos-containing waste

material transported off the facility site as required by 40 C.F.R. § 61.150(d).

67. BPXA discharged visible emissions to the outside air during the collection,

processing, packaging, or transporting of any asbestos-containing waste material in violation of

40 C.F.R. § 61.150(a), and it did not use one of the emission control and waste treatment

methods specified in 40 C.F.R. § 61.150(a)(1) through (4).

CLAIMS

First Claim for Relief(Civil Penalties under Section 311(b) of the Clean Water Act for the March 2006 Leak)

68. The allegations of the foregoing paragraphs are incorporated herein by reference.

69. Beginning on or about March 1 and lasting through about March 6, 2006, a discharge

of oil occurred from the oil transit line near GC-2 in the Greater Prudhoe Bay Unit into the

navigable waters and/or adjoining shorelines in violation of Section 311(b)(3) of the CWA, 33

U.S.C. § 1321(b)(3).

70. BPXA, as an owner and/or operator of the oil transit lines and the Greater Prudhoe

Bay Unit at the time of the discharge near GC-2, is liable for a civil penalty of up to $1,100 per

barrel discharged, pursuant to Section 311(b)(7)(A) of the CWA, 33 U.S.C. § 1321(b)(7)(A), and

40 C.F.R. § 19.4. To the extent that the discharges of oil resulted from gross negligence or

willful misconduct, Defendant is liable for a civil penalty of not less than $130,000 per discharge

and not more than $4,300 per barrel of oil discharged. 33 U.S.C. § 1321(b)(7)(D).

Second Claim for Relief(Civil Penalties under Section 311(b) of the Clean Water Act for the August 2006 Spill)



COMPLAINT - Page 15

72. On or about August 6, 2006, a discharge of oil occurred from the oil transit lines into

the navigable waters and/or adjoining shorelines between flow stations 1 and 2 in the Greater

Prudhoe Bay Unit in violation of Section 311(b)(3) of the CWA, 33 U.S.C. § 1321(b)(3).

73. BPXA, as an owner and operator of the oil transit lines and the Greater Prudhoe Bay

Unit at the time of the discharge between flow stations 1 and 2 in the Greater Prudhoe Bay Unit,

is liable for a civil penalty of up to $1,100 per barrel discharged, pursuant to Section

311(b)(7)(A) of the CWA, 33 U.S.C. § 1321(b)(7)(A), and 40 C.F.R. § 19.4. To the extent that

the discharges of oil resulted from gross negligence or willful misconduct, Defendant is liable

for a civil penalty of not less than $130,000 per discharge and not more than $4,300 per barrel of

oil discharged. 33 U.S.C. § 1321(b)(7)(D).

Third Claim for Relief(Injunctive Relief under Section 301(a) of the Clean Water Act for the March and August Spills)


75. The discharges of oil, alleged in the previous two claims for relief, violated Section

301(a) of the CWA, 33 U.S.C. § 1311(a). Therefore, Defendant is subject to injunctive relief

pursuant to Section 309(b) of the Clean Water Act, 33 U.S.C. § 1319(b), to take all appropriate

action to prevent further discharges from its oil transit lines into waters of the United States.

Unless enjoined, Defendant may continue to violate the Clean Water Act.

Fourth Claim for Relief(Failure to Prepare and Implement an Adequate SPCC Plan at the Greater Prudhoe Bay Unit)


77. At the Greater Prudhoe Bay Unit, BPXA failed to comply with the requirements of

the CWA and the SPCC Regulations promulgated thereunder, by failing to prepare and

implement an SPCC Plan in accordance with good engineering practices, and failing to


COMPLAINT - Page 16

implement certain required spill prevention measures, in violation of 40 C.F.R. §§ 112.3 and

112.7. Specifically, BPXA:

a. failed, in its SPCC Plan, to identify the location of bulk storage containers observed at

the facility, including some stationary tanks, oil-filled operational equipment, oil

separation and treating vessels and equipment, and long-term storage locations for mobile

containers and drums, as required by 40 C.F.R. § 112.7(a)(3);

b. failed, in its SPCC Plan, to indicate the type of oil and the storage capacity for all oil

storage containers of 55 gallons and above, as required by 40 C.F.R. 112.7(a)(3)(i);

c. failed, in its SPCC Plan, to address appropriate containment and/or diversionary

structures or equipment to prevent a discharge, specifically at the oil truck

loading/unloading areas, as required by 40 C.F.R. § 112.7(c);

d. failed to construct all bulk storage tank installations with adequate secondary

containment, specifically at the BOC Bulk Fuel Plant and Bulk Chemical site, as required

by 40 C.F.R. § 112.8(c)(2);

e. failed to construct all container installations in accordance with good engineering

practices to avoid discharges, specifically at the BOC Bulk Fuel Plant and Bulk Chemical

site, as required by 40 C.F.R. § 112.8(c)(8);

f. failed to properly design pipe supports to minimize abrasion and corrosion at all

locations, specifically at the BOC Bulk Fuels site, as required by 40 C.F.R. § 112.8(d)(3);

g. failed to properly close and seal drains or dikes at tank batteries and separation and

treating areas where there is a reasonable possibility of discharge, specifically at GC-3, as

required by § 112.9(b)(1); and


COMPLAINT - Page 17

h. failed, in its SPCC plan, to address appropriate containment for any of the oil

separation and treating vessels and equipment with capacities greater than 55-gallons at

Greater Prudhoe Bay, as required by § 112.9(c)(2).

78. By its failure to prepare and implement an SPCC Plan at the Greater Prudhoe Bay

Unit facility in accordance with good engineering practices, and its failure to implement certain

required spill prevention measures, BPXA violated the regulations at 40 C.F.R. Part 112, issued

under CWA Section 311(j), 33 U.S.C. § 1321(j), which sets forth the requirements for

preparation and implementation of SPCC Plans.

79. Accordingly, pursuant to Section 311(b)(7)(C) of the CWA, 33 U.S.C.

§ 1321(b)(7)(C), as adjusted by 40 C.F.R. § 19.4, BPXA is liable for injunctive relief and a civil

penalty of not to exceed $32,500 per day per violation.

Fifth Claim for Relief(Failure to Prepare and Implement an Adequate SPCC Plan at the Milne Point Unit Facility)


81. At the Milne Point Unit, BPXA failed to comply with the requirements of the CWA

and the SPCC Regulations promulgated thereunder, by failing to prepare and implement an

SPCC Plan in accordance with good engineering practices, and failing to implement certain

required spill prevention measures, in violation of 40 C.F.R. §§ 112.3 and 112.7. In its SPCC

Plan, BPXA specifically:

a. failed to identify the location of bulk storage containers observed at the facility,

including some stationary tanks, oil-filled operational equipment, oil separation and

treating vessels and equipment, and long-term storage locations for mobile containers and

drums, as required by 40 C.F.R. § 112.7(a)(3);


COMPLAINT - Page 18

b. failed to provide sufficient impracticability statements for secondary containment for

mobile and portable tanks and tank battery, separating and treating facility installations as

required by 40 C.F.R. § 112.7(d); and

c. failed to adequately complete an “Applicability of Substantial Harm Criteria”

certification form as required by Appendix C to Part 112.

82. By its failure to prepare and implement an SPCC Plan at the Milne Point Unit facility

in accordance with good engineering practices, and its failure to implement certain required spill

prevention measures, BPXA violated the regulations at 40 C.F.R. Part 112, issued under CWA

Section 311(j), 33 U.S.C. § 1321(j), which sets forth the requirements for preparation and

implementation of SPCC Plans.




Sixth Claim for Relief(Failure to Prepare and Implement an Adequate SPCC Plan at the Badami Unit Facility)


85. At the Badami Unit, BPXA failed to comply with the requirements of the CWA and

the SPCC Regulations promulgated thereunder, by failing to prepare and implement an SPCC

Plan in accordance with good engineering practices, and failing to implement certain required

spill prevention measures, in violation of 40 C.F.R. §§ 112.3 and 112.7. Specifically, BPXA:

a. failed, in its SPCC Plan, to identify the location of bulk storage containers observed at

the facility, including some stationary tanks, oil-filled operational equipment, oil

separation and treating vessels and equipment, and long-term storage locations for mobile

containers and drums, as required by 40 C.F.R. § 112.7(a)(3);


COMPLAINT - Page 19

b. failed, in its SPCC Plan, to indicate the type of oil and storage capacity for all oil

storage containers of 55 gallons and above, as required by 40 C.F.R. §112.7(a)(3)(i);

c. failed, in its SPCC Plan , to provide sufficient impracticability statements for

secondary containment for mobile and portable bulk storage containers, as required by 40

C.F.R. § 112.7(d); and

d. failed, in its SPCC plan, to address appropriate containment for any of the oil

separation and treating vessels and equipment with capacities greater than 55-gallons at

the Badami Unit as required by § 112.9(c)(2).

86. By its failure to prepare and implement an SPCC Plan at the Badami Unit facility in

accordance with good engineering practices, and its failure to implement certain required spill

prevention measures, BPXA violated the regulations at 40 C.F.R. Part 112, issued under CWA

Section 311(j), 33 U.S.C. § 1321(j), which sets forth the requirements for preparation and

implementation of SPCC Plans.




Seventh Claim for Relief(Failure to comply with the Order issued by DOT)


89. The Order required BPXA to take necessary corrective action in the Greater Prudhoe

Bay Unit to protect the public, property, and the environment, pursuant to 49 U.S.C. § 60112.

BPXA violated the Order numerous times, including when:


COMPLAINT - Page 20

a. BP failed to begin weekly cleaning of the 34-inch pipeline segment between Gathering

Center 1 to Skid 50 until about November 7, 2006, which was approximately 149 days

after the Order’s deadline;

b. BP failed to begin weekly cleaning of the 34-inch pipeline between Flow Station 1 and

Skid 50 until about October 10, 2006, which was approximately 120 days after the

Order’s deadline;

c. BP failed to begin the weekly cleaning of the 30-inch pipeline between Flow Station 2

and Flow Station 1 until about July 20, 2006, which was approximately 39 days after the

Order’s deadline;

d. BP failed to perform an internal inspection of the 34-inch pipeline between Gathering

Center 1 and Skid 50 until about November 12, 2006, which was approximately 151 days


e. BP failed to perform an internal inspection of the 34-inch pipeline between Flow

Station 1 and Skid 50 until about October 18, 2006, which was approximately 124 days


f. BP failed to perform an internal inspection of the 30-inch pipeline between Flow

Station 2 and Flow Station 1 until about July 22, 2006, which was approximately 37 days


g. BP failed to perform an internal inspection of the Lisburne pipeline until about June

30, 2006, which was approximately 15 days after the Order’s deadline.

90. Unless enjoined, Defendant may violate the Order and 49 U.S.C. § 60112 again.

91. Pursuant to 49 U.S.C. § 60120, Defendant is liable for civil penalties for each

violation of the Order, considering the same factors as prescribed for the Secretary in an


COMPLAINT - Page 21

administrative case under section 60122, and for injunctive relief.

Eighth Claim for Relief(Failure to comply with asbestos NESHAP)


93. At the Greater Prudhoe Bay Unit, Defendant failed to comply with the requirements

of the asbestos NESHAP, 40 C.F.R. §§ 61.140-61.157, and of Section 112 of the CAA, 42

U.S.C. § 7412. Specifically, Defendant failed to comply by:

a. Failing to conduct a survey of the facility or part of the facility where the renovation

occurred for the presence of asbestos before beginning the renovation;

b. Failing to provide written notification at least 10 working days prior to beginning

asbestos stripping or removal work in March 2006;

c. Failing to adequately wet regulated asbestos-containing materials that were being

stripped from facility components;

d. Failing to adequately wet regulated asbestos-containing material that had been

stripped from facility components and ensure that it remained wet until collected and

contained or treated in preparation for disposal;

e. Failing to have an on-site representative trained in proper removal of regulated

asbestos-containing materials present while regulated asbestos-containing material was

being stripped, removed or otherwise handled or disturbed;

f. Failing to mark vehicles used to transport asbestos-containing waste material during

the loading and unloading of waste;

g. Failing to deposit asbestos-containing waste material at a waste disposal site operated

in accordance with 40 C.F.R. § 61.154;


COMPLAINT - Page 22

h. Failing to maintain waste shipment records for all asbestos-containing waste material

transported off the facility site; and

i. Discharging visible emissions to the outside air during the collection, processing,

packaging, or transporting of asbestos-containing waste material, without using one of

the emission control and waste treatment methods specified in 40 C.F.R. § 61.150(a)(1)

through (4).

94. Unless enjoined, Defendant may continue to violate the asbestos NESHAP and the

CAA.

95. Pursuant to Section 113(b) of the CAA, 42 U.S.C. § 7413(b), as amended by the

Debt Collection Improvement Act of 1996, 31 U.S.C. § 3701, and the Civil Monetary Penalty

Inflation Adjustment Rule, 40 C.F.R. Part 19, Defendant is liable for civil penalties up to

$32,500 per day for each violation and for injunctive relief.

PRAYER FOR RELIEF

WHEREFORE, based upon all the allegations set forth above, Plaintiff United States of

America, prays that this Court:

1. Impose civil penalties on Defendant in an amount of up to $1,100 per barrel of oil

discharged in violation of Section 311(b)(3) of the Clean Water Act, and to the extent

each discharge was the result of gross negligence or willful misconduct by the Defendant,

impose civil penalties of not less than $130,000 for each discharge and up to $4,300 per

barrel of oil discharged;

2. Order Defendant to take all appropriate action to prevent further spills from its facilities

into waters of the United States, in compliance with the Clean Water Act and the SPCC

Regulations;


Exhibit 3 (Part 1 of 2)


Exhibit 3 (Part 2 of 2)


Exhibit 4


IN THE UNITED STATES DISTRICT COURT

FOR THE DISTRICT OF ALASKA ______________________________________ ) ) UNITED STATES OF AMERICA, ) ) Plaintiff, ) Civil No. 3:09-cv-00064-JWS ) v. ) ) CONSENT DECREE BP EXPLORATION (ALASKA) INC., ) ) Defendant. ) ) ______________________________________ )

TABLE OF CONTENTS I. JURISDICTION AND VENUE ...................................................................................... 2 II. APPLICABILITY ............................................................................................................ 3 III. DEFINITIONS ................................................................................................................. 4 IV. CIVIL PENALTY ............................................................................................................ 8 V. COMPLIANCE REQUIREMENTS ................................................................................ 9 VI. REPORTING REQUIREMENTS ................................................................................. 32 VII. STIPULATED PENALTIES ......................................................................................... 39 VIII. FORCE MAJEURE ....................................................................................................... 43 IX. DISPUTE RESOLUTION ............................................................................................. 45 X. INFORMATION COLLECTION AND RETENTION ................................................ 48 XI. EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS ...................................... 51 XII. COSTS ........................................................................................................................... 53 XIII. NOTICES ....................................................................................................................... 53 XIV. EFFECTIVE DATE ....................................................................................................... 55 XV. RETENTION OF JURISDICTION ............................................................................... 55 XVI. MODIFICATION .......................................................................................................... 55 XVII. TERMINATION ............................................................................................................ 56 XVIII. PUBLIC PARTICIPATION .......................................................................................... 57 XIX. SIGNATORIES/SERVICE ............................................................................................ 57 XX. INTEGRATION ............................................................................................................ 58 XXI. FINAL JUDGMENT ..................................................................................................... 58 XXII. APPENDICES ............................................................................................................... 58

Case 3:09-cv-00064-JWS Document 47 Filed 07/20/11 Page 1 of 78Case 2:08-cv-01008-MJP Document 174-6 Filed 10/14/11 Page 2 of 79

1

Plaintiff United States of America, on behalf of the United States Environmental

Protection Agency (EPA) and the United States Department of Transportation (DOT), has filed a

complaint in this action on March 31, 2009, alleging that Defendant BP Exploration (Alaska),

Inc. (BPXA), violated the Clean Water Act, 33 U.S.C. §§ 1311, 1319, 1321, as amended by the

Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq.; the Clean Air Act, 42 U.S.C. §§ 7401-

7671q; and the Federal Pipeline Safety Laws, 49 U.S.C. § 60101 et seq. The Clean Water Act

claims alleged in the Complaint arise from two unauthorized discharges of crude oil into

navigable waters of the United States from BPXA’s pipelines of the Prudhoe Bay Unit (PBU) on

the North Slope of Alaska in the spring and summer of 2006, as well as violations of the Spill

Prevention Control and Countermeasure (SPCC) regulations promulgated pursuant to the Clean

Water Act. The Clean Air Act claims in the Complaint arise from the alleged improper removal

of asbestos-containing materials from its pipelines in the spring and summer of 2006, in violation

of the National Emission Standards for Hazardous Air Pollutants (NESHAP) for asbestos,

promulgated by EPA under 42 U.S.C. § 7412, and codified at 40 C.F.R. §§ 61.140-61.157. The

Pipeline Safety Law claims arise from BPXA’s alleged failure to comply with an order issued by

the Pipeline and Hazardous Materials Safety Administration (PHMSA) of DOT pursuant to 49

U.S.C. § 60112, requiring BPXA to perform certain corrective actions on its pipelines.

Defendant does not admit any liability to the United States arising out of the

transactions or occurrences or any of the facts alleged in the Complaint, and, other than for

purposes of this Consent Decree, Defendant does not admit the United States’ jurisdiction under

the Clean Water Act, the Clean Air Act, or the Pipeline Safety Laws.


2

Defendant has started implementation and operation of some corrective measures,

including replacement of the Prudhoe Bay oil transit lines, improved leak detection on the oil

transit lines, and improved operation and maintenance of the Pipeline System;

The Parties recognize, and the Court by entering this Consent Decree finds, that

this Consent Decree has been negotiated by the Parties in good faith and will avoid litigation

between the Parties and that this Consent Decree is fair, reasonable, and in the public interest.

NOW, THEREFORE, before the taking of any testimony, without the

adjudication or admission of any issue of fact or law, and with the consent of the Parties, IT IS

HEREBY ADJUDGED, ORDERED, AND DECREED as follows:

I. JURISDICTION AND VENUE

1. Plaintiff and, solely for purposes of this Consent Decree, Defendant, agree that

this Court has jurisdiction over the subject matter of this action, pursuant to 33 U.S.C.

§§ 1319(b) and 1321(b)(7)(E) and (n), 42 U.S.C. § 7413(b), 49 U.S.C. § 60120(a)(1), and

28 U.S.C. §§ 1331, 1345, and 1355, and over the Parties. Venue lies in this District

pursuant 33 U.S.C. § 1321(b)(7)(E), 42 U.S.C. § 7413(b), and 28 U.S.C. §§ 1391 and

1395 because the violations that are the subject of this action occurred in this District,

and Defendant is located in, does business in, and is found in this District. Solely for

purposes of this Decree or any action to enforce this Decree, Defendant consents to the

Court’s jurisdiction over this Decree and any such action and over Defendant and

consents to venue in this judicial district.

2. Solely for purposes of this Consent Decree, Defendant agrees that the Complaint

states claims upon which relief may be granted.


3

II. APPLICABILITY

3. The obligations of this Consent Decree apply to and are binding upon the United

States and upon Defendant and any successors, assigns, or other entities or persons

otherwise bound by law.

4. No transfer of ownership or operation of the PBU or of the Pipeline System,

whether in compliance with the procedures of this Paragraph or otherwise, shall relieve

Defendant of its obligation to ensure that the terms of the Decree are implemented. At

least 30 Days prior to such transfer, Defendant shall provide a copy of this Consent

Decree to the proposed transferee and shall simultaneously provide written notice of the

prospective transfer, together with a copy of the proposed written agreement, to EPA

Region 10, DOT-PHMSA, the United States Attorney for the District of Alaska, and the

United States Department of Justice, in accordance with Section XIII of this Decree

(Notices). Any attempt to transfer ownership or operation of the PBU or of the Pipeline

System without complying with this Paragraph constitutes a violation of this Decree.

5. Defendant shall provide a copy of this Consent Decree to all officers, employees,

and agents whose duties might reasonably include compliance with any provision of this

Decree, as well as to any contractor retained to perform work required under this Consent

Decree. Alternatively, Defendant may fulfill the obligation in the preceding sentence by

providing the foregoing persons with instruction and briefing concerning portions of this

Consent Decree for which they have implementation responsibilities, along with the


4

relevant portions of the Consent Decree. Defendant shall condition any such contract

upon performance of the work in conformity with the terms of this Consent Decree.

6. In any action to enforce this Consent Decree, Defendant shall not raise as a

defense the failure by any of its officers, directors, employees, agents, or contractors to

take any actions necessary to comply with the provisions of this Consent Decree.

III. DEFINITIONS

7. Terms used in this Consent Decree that are defined in the Federal Pipeline Safety

Laws, the Clean Water Act, the Clean Air Act, or in regulations promulgated pursuant to

Federal Pipeline Safety Laws, the Clean Water Act, or the Clean Air Act shall have the

meanings assigned to them in such laws or regulations, unless otherwise provided in this

Decree. Whenever the terms set forth below are used in this Consent Decree, the

following definitions shall apply:

a. “Actionable Anomaly” shall have the meaning provided in

Appendix C;

b. “ASME B31.4” shall mean the document titled Pipeline

Transportation Systems for Liquid Hydrocarbons and other Liquids, 2006, or any

updated version of this document that becomes effective during the duration of

this Consent Decree.

c. “BPXA” and “the Company” shall mean Defendant BP

Exploration (Alaska), Inc.;

d. “CAO” shall mean the Corrective Action Order issued by the

Associate Administrator, Pipeline and Hazardous Materials Safety


5

Administration, to BPXA on March 15, 2006, and amended on July 20, 2006

(Amendment No. 1 to Corrective Action Order); August 10, 2006 (Amendment

No. 2 to Corrective Action Order); and April 27, 2007 (Amendment No. 3 to

Corrective Action Order);

e. “Complaint” shall mean the complaint filed by the United States in

this action;

f. “Consent Decree” or “Decree” shall mean this Decree and all

appendices attached hereto (listed in Section XXII);

g. “Day” shall mean a calendar day unless expressly stated to be a

business day. In computing any period of time under this Decree, where the last

day would fall on a Saturday, Sunday, or federal holiday, the period shall run

until the close of business of the next business day.

h. “Defendant” shall mean BP Exploration (Alaska), Inc. (BPXA);

i. “DOT” shall mean the United States Department of Transportation

and includes the Pipeline and Hazardous Materials Safety Administration

(PHMSA) and any of their successor departments or agencies;

j. “EPA” shall mean the United States Environmental Protection

Agency and any of its successor departments or agencies;

k. “Effective Date” shall have the definition provided in Section XIV;


6

l. “Federal Pipeline Safety Laws” shall mean the laws set forth in 49

U.S.C. § 60101 et seq., and the implementing regulations at 49 C.F.R. Parts 190 -

199;

m. “ILI Piggable Flow Lines” shall mean those flow lines in the

Pipeline System listed on Appendix A that have permanent launchers and

receivers or which are currently configured to use a temporary launcher and

receiver for in-line-inspection (“ILI”) pigging, and any additional flow lines in the

Pipeline System that are made ILI piggable during the period of this Decree;

n. “Maintenance Piggable Flow Lines” shall mean those flow lines in

the Pipeline System which are listed on Appendix A that have permanent

launchers and receivers, and any additional flow lines in the Pipeline System that

are made maintenance piggable, with the addition of permanent launchers and

receivers, during the period of this Decree;

o. “OTLs” shall mean the Eastern Operating Area (EOA) and

Western Operating Area (WOA) hazardous liquid pipelines that transport

processed crude oil from the EOA flow stations and WOA gathering centers to

the Prudhoe Bay Unit (PBU) Skid 50 facility. For purposes of Paragraph 13,

OTLs shall also include the Lisburne hazardous liquid pipeline that transports

processed crude oil from the Lisburne Production Center to Pump Station 1 of the

Trans Alaska Pipeline System. The OTLs are depicted on the map attached to

this Decree as Appendix A;


7

p. “Paragraph” shall mean a portion of this Decree identified by an

Arabic numeral;

q. “Parties” shall mean the United States and BPXA;

r. “Pipeline System” or “BPXA’s Pipeline System” shall mean well

lines, flow lines, and produced water lines operated by BPXA that are used to

move liquid hydrocarbons between the well pads and the PBU EOA flow stations

and WOA gathering centers in the Prudhoe Bay Unit oil field on the North Slope

of Alaska. The Pipeline System consists of those well lines, flow lines, and

produced water lines set forth in the lists and maps attached to this Decree as

Appendix A;

s. “PBU” shall mean the Prudhoe Bay Unit.

t. “RSTRENG” shall mean AGA Pipeline Research Committee

Project PR-3-805 “A Modified Criterion for Evaluating the Remaining Strength

of Corroded Pipe" (December 1989), or any updated version of this criterion for

the duration of this Consent Decree that is no less stringent than the referenced

version.

u. “Section” shall mean the portion of this Decree identified by a

Roman numeral;

v. “United States” shall mean the United States of America, acting on

behalf of the U.S. Department of Transportation and the U.S. Environmental

Protection Agency.


8

IV. CIVIL PENALTY

8. Within thirty (30) Days after the Effective Date of this Consent Decree,

Defendant shall pay the sum of $25 million as a civil penalty, together with interest

accruing from the date on which the Consent Decree is lodged or January 31, 2011,

whichever date is earlier, at the rate specified in 28 U.S.C. § 1961.

9. Defendant shall pay the civil penalty due by FedWire Electronic Funds Transfer

(EFT) to the U.S. Department of Justice in accordance with written instructions to be

provided to Defendant, following lodging of the Consent Decree, by the Financial

Litigation Unit of the U.S. Attorney’s Office for the District of Alaska. At the time of

payment, Defendant shall send a copy of the EFT authorization form and the EFT

transaction record, together with a transmittal letter, which shall state that the payment is

for the civil penalty owed pursuant to the Consent Decree in United States v. BPXA, and

shall reference the civil action number 3:09-cv-00064-JWS and DOJ case number 90-5-

1-1-08808 and to the United States in accordance with Section XIII of this Decree

(Notices); by email to [email protected]; and by mail to:

EPA Cincinnati Finance Office 26 Martin Luther King Drive Cincinnati, Ohio 45268

10. Defendant shall not deduct any penalties paid under this Decree pursuant to this

Section or Section VII (Stipulated Penalties) in calculating its federal income tax.


9

V. COMPLIANCE REQUIREMENTS

General Requirements

11. Compliance with Applicable Laws. This Consent Decree is not a permit, or a

modification of any permit, under any federal, State, or local laws or regulations.

Defendant is responsible for achieving and maintaining complete compliance with all

applicable federal, State, and local laws, regulations, and permits; and Defendant’s

compliance with this Consent Decree shall be no defense to any action commenced

pursuant to any such laws, regulations, or permits, except as set forth herein. The United

States does not, by its consent to the entry of this Consent Decree, warrant or aver in any

manner that Defendant’s compliance with any aspect of this Consent Decree will result in

compliance with provisions of the Federal Pipeline Safety Laws, the Clean Water Act, or

the Clean Air Act, or with any other provisions of federal, State, or local laws,

regulations, or permits.

12. OTL Replacement Certification. BPXA hereby certifies, in accordance with

Paragraph 41, that it has replaced the EOA and WOA OTLs that were the subject of the

CAO and has dismantled and removed, or abandoned, each OTL segment that was

removed from operation.

13. Applicability of 49 C.F.R. Parts 195 and 199 to OTLs. The OTLs are currently

low stress hazardous liquid pipelines regulated under 49 C.F.R. Part 195. However, as of

the Effective Date, BPXA shall operate the OTLs in compliance with all requirements of

49 C.F.R. Parts 195 and 199, sooner than is otherwise required by regulation. For the

purposes of determining what parts of the regulations shall apply, and when they shall


10

apply to the OTLs, the OTLs shall be treated as though they are operated above twenty

percent (20%) of the specified minimum yield strength of the line pipe. The OTLs shall

be deemed “could affect a High Consequence Area” pipelines according to 49 C.F.R.

§ 195.452(a). PHMSA may inspect for compliance with and enforce all of the

requirements of 49 C.F.R. Parts 195 and 199 on the OTLs, by all means set forth in the

Pipeline Safety Laws, 49 U.S.C. § 60101 et seq., and the implementing regulations at 49

C.F.R. Parts 190-199.

14. Complying with the requirements of Paragraph 13 does not relieve Defendant of

any obligations under the Clean Water Act or implementing regulations or any other

federal, state or local law, regulation, permit or other requirement.

15. Emergency Repair Equipment and Materials. Within ninety (90) Days of the

Effective Date, BPXA shall obtain or place orders for and maintain for the duration of

this Consent Decree the emergency repair equipment and materials set forth in Appendix

B.

Spill Prevention Countermeasure and Control Requirements

16. BPXA hereby certifies, in accordance with Paragraph 41, that it has prepared and

implemented an SPCC Plan at the Greater Prudhoe Bay facility, the Milne Point facility,

and the Badami facility in accordance with good engineering practices and the

regulations at 40 C.F.R. Part 112, issued under CWA Section 311(j), 33 U.S.C. § 1321(j).

Asbestos Requirements

17. BPXA shall amend its mandatory employee and contractor safety training course

content and materials to include asbestos awareness information. This information shall


11

include descriptions of materials known and suspected to contain asbestos, and shall

include photos of the material to enable employees to visually identify potentially

asbestos-containing materials. Furthermore, the training shall reference BPXA’s

Asbestos Management Program, which details requirements for sampling and handling of

asbestos by trained personnel and for alerting BPXA about the presence of possible or

suspect asbestos containing materials.

18. BPXA shall provide a copy of the training materials to EPA for review and

approval within three (3) months of the Effective Date. BPXA shall not modify that

portion of its safety training during the term of this Consent Decree without prior

approval from EPA.

Pipeline System-Wide Integrity Management Program Requirements

19. Elements of the Pipeline System-Wide Integrity Management Program. BPXA

shall develop and implement a written Pipeline System-Wide Integrity Management

Program (“IM Program”). The purpose of the IM Program is to reduce the likelihood and

magnitude of unpermitted discharges from the Pipeline System. The Pipeline System-

Wide IM Program shall have the following seven (7) elements (Elements):

20. Element 1 – Data and Information Collection.

a. Within ninety (90) Days of the Effective Date, BPXA shall

develop and submit to the United States for approval, pursuant to Paragraphs 45-

49, a procedure (“Data and Information Collection Procedure”) to identify,

collect, and document, the following data and information, where available, for

each pipeline in the Pipeline System:


12

i. Pipeline inventory information

(1) Pipeline name

(2) Pipeline boundary limit description

(3) Pipeline service

ii. Existing pipeline engineering and design data

(1) Nominal pipe size

(2) Nominal wall thickness

(3) Material specifications, including: pipe manufacturing

method and date, construction method, pipe grade, and other

relevant material data;

(4) Design code

(5) Design maximum operating pressure (MOP)

(6) History of all permanent changes to MOP

(7) External coating type if applicable

(8) General insulation type

(9) Installation date

(10) Information related to hydrostatic testing

(11) Piggability (whether the pipeline is capable of

accommodating maintenance pigs and/or ILI tools)

(12) Wind induced vibration (WIV) dampeners

iii. Pipeline physical inspection data, including historic data


13

(1) Inspection results, including, but not limited to: indications

of corrosion, dents, gouges, grooves and the location, type, nature

and severity of each indication.

(2) Inspection type and the types and sizes of defect that the

inspection method can detect

(3) Inspection locations

(4) Inspection dates

iv. Corrosion monitoring devices

(1) Type

(2) Location

(3) Orientation

v. Fluid Composition Data

(1) Composition of the fluids and materials

(2) The corrosive characteristics and integrity threats presented

by such fluids and materials

(3) Historical water cuts, CO2, and H2S levels

(4) Compositional analyses, bioassays and data analyzing

potential biological, chemical and physical interactions among the

components of the fluids and materials

(5) Sediment accumulations that are either known or suspected

on the basis of any available information.

vi. Corrosion inhibitor type and effectiveness


14

vii. Pipeline repairs (dates, locations, type of repair, type of defect

repaired)

viii. Pipeline leaks (dates and locations)

ix. Pipeline structural supports

(1) Type – (vertical support members (VSM) or horizontal

support members (HSM))

(2) Location

(3) Movement, subsidence, and jacking

x. Geographical data

(1) Pipeline profile

(2) Rivers and flood plains

(3) Topography

(4) Potential pipeline release volumes

(5) Distances between isolation points

xi. Operational data

(1) Annual average volumetric flow rate

(2) Annual average operating temperature

(3) Annual average operating pressure

xii. Any other data or information BPXA believes is relevant to

Pipeline System safety and integrity.

b. BPXA’s Data and Information Collection Procedure shall describe

how the information is used as part of its Risk Based Assessment Procedure


15

required in Element 3 below to characterize, integrate and analyze the data and

information to determine the threats on each pipeline in the Pipeline System.

c. BPXA shall make this pipeline integrity management data and

information readily available to BPXA personnel and contractors responsible for

Pipeline System operations, integrity, and maintenance, and for performing the

work required by this Decree.

d. This element shall be integrated with all other elements of the

Pipeline System-Wide Integrity Management Program, meaning that BPXA’s

operations and maintenance decisions and the work required by this Decree shall

be based on all available information about pipeline threats and risks.

e. BPXA’s Risk Based Assessment Procedure shall include a process

for identifying, collecting, documenting and incorporating new data and

information as it becomes available. However, BPXA shall incorporate data and

information from any pipeline inspection no later than 180 Days after the

inspection. If BPXA can demonstrate that a 180 Day period is impracticable for

any given inspection, the Parties may agree in writing to a longer period.

f. BPXA shall begin implementation of its Data and Information

Collection Procedure upon approval by the United States in accordance with

Paragraphs 45-49 of this Decree. BPXA shall certify in accordance with

Paragraph 41 that it has collected, documented, characterized, integrated and

incorporated all required data and information listed in Paragraph 20(a) into this

Data and Information Collection Element by the latest to occur of December 31,


16

2011, or 90 days after the approval of the Data and Information Collection

Procedure submitted for approval under Paragraph 20(a), for all well lines, flow

lines and produced water lines in the Pipeline System.

g. BPXA shall promptly provide any data and information contained

within the Data and Information Collection Element to the United States upon

request.

21. Element 2 – Pipeline Inspection.

a. In-Line Inspection: BPXA shall assess its ILI Piggable Flow Lines

with ILI tools and retain all data and documentation of the results. For all ILI

inspections, BPXA shall use calibrated, instrumented ILI tools capable of

identifying and characterizing the location, percentage metal loss, geometry and

areal dimensions of corrosion anomalies. Such tools shall also be capable of

identifying deformation anomalies including dents, gouges and grooves. BPXA

shall validate and document ILI tool performance to confirm identification

thresholds, probability of detection, probability of proper identification, and the

accuracy of sizing, linear and orientation measurements, and other characteristics.

BPXA shall use high resolution magnetic flux leakage tools or ultrasonic tools

for the detection of internal and external corrosion. BPXA shall use high

resolution magnetic flux leakage tools or ultrasonic tools for the detection of

deformation anomalies, followed by physical examination for sizing, or caliper

tools for detection and sizing. If BPXA selects other ILI tool types, BPXA shall

explain and document the basis for selection of those tools. BPXA shall:


17

i. within two years of the Effective Date, certify in accordance with

Paragraph 41 that it has used ILI tools to inspect each ILI Piggable Flow

Line that has not been inspected with ILI tools in the previous five (5)

years;

ii. certify in accordance with Paragraph 41 that it has reinspected

each ILI Piggable Flow Line by conducting ILI runs no greater than every

five (5) years from the date of the previous ILI run. BPXA shall reinspect

such lines with ILI tools more frequently if the Risk Ranking required by

Paragraph 22 indicates the need to do so to ensure pipeline integrity; and

iii. schedule ILI inspections taking into consideration its most current

Risk Ranking required by Paragraph 22.

iv. In the Report required by Paragraph 37, BPXA shall submit the

schedule of all ILI inspections and the basis for scheduling such

inspections. BPXA shall provide access to all final ILI reports via the

Portal required by Paragraph 36.

b. Electric Resistance Probes and Coupons: For each line in the

Pipeline System, BPXA shall use, at a minimum, one of the following methods to

monitor the internal rate of corrosion on each line: (1) electric resistance probes

(ER Probes), or (2) corrosion weight loss coupons (Coupons). When installing or

relocating Coupons and ER Probes, BPXA shall locate them in the corrosive

phase. For example, if internal corrosion is expected to occur at the bottom of a

horizontal line, such ER Probes and Coupons shall be located in that position.


18

When installing or relocating Coupons and ER Probes, BPXA shall document

such work and comply with Appendix E, Location of Corrosion Monitoring

Devices. BPXA shall:

i. certify in accordance with Paragraph 41 that ER Probes and/or

Coupons are present on all flow lines in the Pipeline System within one

(1) year of the Effective Date;

ii. certify in accordance with Paragraph 41 that ER Probes and/or

Coupons are present on all well lines and produced water lines in the

Pipeline System within two (2) years of the Effective Date;

iii. certify at least yearly in accordance with Paragraph 41 that it has

monitored and inspected all ER Probes and Coupons in accordance with

the frequencies set out in Appendix D, Requirements of BPXA Inspection

Frequency, but Coupon monitoring frequency shall be long enough such

that any corrosion can be detected;

iv. certify in accordance with Paragraph 41 that it has reviewed and

documented all of its active Coupon and ER Probe locations to ensure

they are in locations which provide the required corrosion rate data within

two (2) years of the Effective Date. BPXA shall perform such review in

accordance with Appendix E, Corrosion Monitoring Device

Requirements. Within three years of the Effective Date, BPXA shall

relocate Coupons and ER Probes which are not located in the corrosive


19

phase or are otherwise not located in accordance with Appendix E, and

shall document such work.

v. If BPXA can demonstrate that installation or relocation of

Coupons or ER Probes in accordance with Appendix E is impracticable

for a particular pipeline and that corrosion rates can be reliably monitored

by other means, the Parties may agree in writing to a substitute method of

determining corrosion rates.

vi. In the Reports required by Paragraph 37, BPXA shall state which

Pipeline System pipelines showed an increase in internal corrosion rates as

shown by Coupon, ER Probe or other data and explain BPXA’s actions in

response to such information. Only in the first Report required by

Paragraph 37, BPXA shall provide a pipeline-by-pipeline list of all

Coupons and ER Probes, the type, o’clock position, monitoring frequency

(for Coupons), and location of each Coupon or Probe.

c. Additional Inspections: In addition to the inspections and use of

Coupons and ER Probes described in the previous Paragraphs, BPXA shall

perform and document the inspections of each Pipeline System pipeline set out in

Appendix D Pipeline Inspection Frequency Chart, and shall perform such

inspections within the timeframes set out therein. However, BPXA shall assess

and inspect pipelines in the Pipeline System more frequently if the most current

Risk Ranking required by Paragraph 22 indicates the need to do so to ensure

pipeline integrity. BPXA shall schedule all additional inspections and


20

reinspections on the basis of its most current Risk Ranking required by Paragraph

22.

d. For information purposes, BPXA shall provide the most current

inspection schedule for each Pipeline System pipeline in the Reports required

pursuant to Paragraph 37. The inspections described in such schedule shall not be

limited to those required by this Decree.

22. Element 3 – Risk Based Assessment and Ranking.

a. Within ninety (90) days of the Effective Date, BPXA shall develop

and submit to the United States for approval a Risk Based Assessment Procedure

according to Paragraphs 45-49 of this Decree. The Risk Based Assessment

Procedure shall provide a mechanism for BPXA to perform a relative risk-ranking

of all pipelines within the Pipeline System (Risk Ranking). The Risk Ranking

shall be based upon and account for all applicable data and information contained

in the Data and Information Program Element required pursuant to Paragraph 20.

When data of suspect quality or consistency is encountered, such data shall be

clearly identified and appropriate consideration given to such concerns during the

analysis process. If data is compromised or incomplete, BPXA shall document

and apply conservative assumptions and explain in the Risk Ranking Report

required in Paragraph 22 how any such conservative assumptions were

determined and used. BPXA’s Risk Based Assessment Procedure shall describe

how all threats and risks to each pipeline are evaluated and assigned values in the

Risk Ranking; describe what models or algorithms were used to assign risk-


21

ranking values and how they were used; and describe the extent of, and basis for,

any assumptions about threats or risks.

b. BPXA shall implement the Risk Based Assessment Procedure

upon its approval. Within ninety (90) days of approval of the Risk Based

Assessment Procedure, BPXA shall submit to the United States a Risk Ranking

Report for all flow lines in the Pipeline System and by March 31, 2012 , BPXA

shall submit to the United States a Risk Ranking Report for all flow lines, well

lines, and produced water lines in the Pipeline System. The Risk Ranking Report,

as applicable to each category of lines for each year’s report, shall include: (1) a

ranking of all pipelines in the Pipeline System ordered from highest to lowest risk

lines; (2) a description of the principal threats that drive the risk ranking for each

pipeline, the relative probability of occurrence of those threats; the assumptions

that were used to generate each threat or assessed risk; and the severity of

consequences from the threats that drive the risk; and (3) a list of the length,

diameter, material(s) carried, and average daily throughput of each pipeline.

c. BPXA shall annually revise its Risk Ranking Report based on new

or changed data or information about its Pipeline System pipelines. BPXA shall

include the most current Risk Ranking Report in the Report required pursuant to

Paragraph 22.

23. Element 4 – Geographic Information System. BPXA has initiated development of

a Geographic Information System (GIS) to organize and display information about the

conditions and characteristics of its Pipeline System and the OTLs. BPXA’s GIS shall


22

include a database of high-resolution digital photography and mapping data for the

Pipeline System and the OTLs which, through the use of software tools, can display or

link to the data and information about the Pipeline System contained in the Data and

Information Collection Element described in Paragraph 20, as well as data and

information on the OTLs, to produce reports and displays of such layered data and

information. Within sixty (60) Days of the Effective Date, BPXA shall provide access to

the United States, in accordance with Section VI , its functional GIS for the Pipeline

System and the OTLs. Within one (1) year of the Effective Date, BPXA shall certify in

accordance with Paragraph 41 that it has trained BPXA employees and contractors in the

use of the GIS. This training may be limited to those BPXA employees and contractors

whose responsibilities include or are related to the operations, integrity and maintenance

of the Pipeline System and the OTLs and performing the work required by this Decree.

Each Pipeline System pipeline shall be named consistently throughout the Pipeline

System-Wide Integrity Management Program, to allow for accurate cross referencing

among system attributes, inspection data and other data and information. Defendant may

assert that information made available to the United States is protected as Confidential

Business Information (CBI) as set out in Paragraph 81 below.

24. Element 5 – Risk Prevention and Mitigation.

a. Within one (1) year of the Effective Date, BPXA shall develop,

implement and submit to the United States one or more procedures to prevent and

mitigate corrosion and other threats to the integrity of the Pipeline System. The

purpose of these procedures is to enable BPXA to: (1) determine the corrosion


23

mechanism(s) on each pipeline; (2) optimize corrosion control (e.g. test corrosion

inhibitors, adjust dosage, etc.); and (3) evaluate the effect of changing operational

conditions including, but not limited to, flow velocities and changing fluid

characteristics.

b. Beginning on the Effective Date and continuing until termination

of this Decree, BPXA shall take the following measures to prevent and mitigate

threats to pipeline integrity including, but not limited to, the regular use of

maintenance pigs and corrosion inhibitors, fluid and materials sampling, projects

to make unpiggable pipelines capable of accommodating maintenance pigs and

ILI tools, damage prevention efforts, and more frequent inspections with ILI

and/or other tools. BPXA shall use the Data and Information Collection Element

required by Paragraph 20 and its most current Risk Ranking Report as the basis

for the selection of prevention and mitigation measures for a particular pipeline or

group of pipelines in the Pipeline System.

i. BPXA shall run maintenance pigs on each Maintenance Piggable

Flow Line at least twice a year, at intervals not to exceed 7 ½ months.

ii. BPXA shall document the date and type(s) of pig used, and any

sediment, water or other materials recovered from each pig run.

c. Within three (3) years of the Effective Date, BPXA shall, in

addition to the other work required by this Decree, perform certain work on the

ten (10) currently non ILI-piggable flow lines in the Pipeline System which

present the highest risk in the Pipeline System, as indicated by the Risk Ranking


24

Report required pursuant to Paragraph 7b. For each of the ten (10) highest risk

non ILI-piggable flow lines BPXA shall either:

(1) make the pipeline ILI Piggable;

(2) remove the pipeline from service;

(3) remove the pipeline from service and replace the pipeline;

or

(4) inspect 100 percent of the length and circumference of the

pipeline at the following locations: inside casings, at water

crossings, where external insulation may be compromised such

that water may be trapped inside the insulation, and where there

are known or suspected accumulations of sediments or water. For

such inspections, BPXA shall use a technology or combinations of

technologies capable of identifying and characterizing the location,

percentage metal loss, geometry and areal dimensions, internal and

external metal loss anomalies. BPXA shall repair any anomalous

conditions pursuant to the Pipeline System Repair provisions in

Paragraph 25. BPXA’s Risk Prevention and Mitigation Procedure

shall provide for an annual review, and update as needed, of each

of its risk prevention and mitigation measures based on new or

changed data and information about the Pipeline System. This

annual review and any updates shall include an assessment of the

effectiveness of previous prevention and mitigation measures.


25

d. In the Report required by Paragraph 37, BPXA shall state the

prevention and mitigation measures that have been implemented on each Pipeline

System pipeline and the basis for selection of such measures (to the extent that a

group of well lines or produced water lines carries similar materials, such

pipelines may be grouped together for the purposes of reporting). BPXA shall

also explain any changes that have been made to the prevention and mitigation

measures on each Pipeline System pipeline or group of pipelines and the basis for

such changes. BPXA shall also report on the status of making certain lines ILI

Piggable.

25. Element 6 – Pipeline System Repair. BPXA shall promptly act on all anomalous

conditions BPXA discovers by any means on the Pipeline System.

a. BPXA shall evaluate all anomalous conditions BPXA discovers by

any means on the Pipeline System and either: (1) repair those Actionable

Anomalies that could reduce a pipeline’s integrity as defined in Appendix C;

(2) derate the Maximum Operating Pressure of the pipeline; or (3) remove the

pipeline from operational service. The time frame for investigation and

subsequent repair, when required, shall be in accordance with the schedules in

Appendix D. If a pipeline with an Actionable Anomaly is to remain in service,

BPXA must demonstrate that the anomalous condition is unlikely to pose a threat

to the long-term integrity of the pipeline.

b. BPXA shall be deemed to have “discovered” a condition when it

has enough information about the condition to determine that the condition


26

presents a potential threat to the integrity of the pipeline. BPXA must promptly,

but no later than 180 Days after any inspection or assessment, obtain enough

information about a condition to make that determination, unless BPXA can

demonstrate that the 180-Day period is impracticable for such inspection or

assessment, in which case the Parties may agree to a different time period

c. When evaluating anomalous conditions, BPXA shall perform

B31G Modified or RSTRENG methods to determine if the pipeline can withhold

the pipeline’s Maximum Operating Pressure while still retaining the pipeline’s

design safety factor when corrosion has caused pipe wall loss.

d. When repairs are required, BPXA shall make such repairs in

accordance with ASME B31.4, “Pipeline Transportation Systems for Liquid

Hydrocarbons and other Liquids.”

e. BPXA shall document all investigations and evaluations of

anomalous conditions and repairs and provide a pipeline-by-pipeline list of the

investigations and repairs completed in the Reports required pursuant to

Paragraph 37 of this Decree. If BPXA permanently derates the MOP of any

pipeline or removes any pipeline from service, BPXA shall explain the basis for

such action in the Reports. BPXA shall also describe the known or suspected

corrosion mechanism on each Pipeline System pipeline or group of pipelines (to

the extent that a group of well lines or produced water lines carries similar

materials, such pipelines may be grouped together for the purposes of reporting).


27

26. Element 7 – Continual Program Improvement. Within one (1) year of the

Effective Date, BPXA shall develop, submit, and implement a procedure for continual

improvement of its System-Wide IM Program. BPXA shall submit a detailed

explanation of its System-Wide IM Program improvement activities in the Reports

required pursuant to Paragraph 37 of this Decree.

Leak Detection

27. Evaluation of LEOS Pilot Project. Within one hundred eighty (180) Days of the

Effective Date, BPXA shall provide a report detailing the results of its LEOS external

leak detection system pilot test and whether and how the LEOS system can improve leak

sensitivity and response times. The report shall include an analysis of the results of the

LEOS system pilot test according to each of the Leak Detection Assessment Criteria

attached to this Decree as Appendix F. In particular, the report shall describe whether

and how the LEOS system can improve leak sensitivity and response times.

28. Evaluation of ATMOS Pilot. Within one hundred eighty (180) Days of the

Effective Date, BPXA shall provide a report detailing the results of its ATMOS leak

detection software pilot, and the results of any additional leak detection system software

pilots. The report shall include an analysis of the results of the ATMOS system pilot test

according to each of the Leak Detection Assessment Criteria attached to this Decree as

Appendix F. In particular, the report shall describe whether and how the ATMOS system

can improve leak sensitivity and response times.

29. Leak Detection Technology Evaluation. BPXA shall comprehensively research

leak detection technologies or systems, which could include a comparison of those


28

technologies or systems to ATMOS and LEOS, that have the potential to improve leak

detection sensitivity and response time. Within ninety (90) Days of the submittal of the

LEOS and ATMOS pilot reports, BPXA shall provide a report detailing the review of

such other leak detection technologies or systems and shall address, at a minimum the

following criteria: the ability to detect leaks, the ability to detect the size of a leak, the

smallest leak that the technology can detect, the ability to determine leak location, the

ability to determine release volume, effectiveness on shut-in pipelines, retrofit feasibility,

instrument accuracy, personnel training and qualifications, and maintenance

requirements. In the report, BPXA shall provide its assessment of the feasibility of

applying each reviewed technology to the OTLs and other transmission lines, and

upstream pipelines in the Pipeline System. BPXA shall assess the potential benefits of

using each technology.

Independent Monitoring Contractor

30. In accordance with the procedure in Paragraph 31, BPXA shall hire an

Independent Monitoring Contractor (IMC) to perform the duties in Paragraph 33.

BPXA’s contract with the IMC shall require the IMC to perform, at a minimum, all of the

duties in Paragraph 33, to provide reports to the United States pursuant to Paragraph 33,

and to be fully available to consult with the United States. BPXA shall bear all costs

associated with the IMC, cooperate fully with the IMC, and provide the IMC with access

to all data, information, records, employees, contractors, and facilities within the Pipeline

System that the IMC deems necessary to effectively perform the duties described in

Paragraph 33.


29

31. Hiring Process. Within thirty (30) Days of the Effective Date of this Consent

Decree, BPXA shall submit to the United States a list of two or more proposed

consultants to serve as the IMC along with their qualifications and descriptions of any

previous work or contracts with BPXA. Each proposed consultant must employ one or

more registered professional engineers experienced in:

a. the principles and use of ILI technology, and the interpretation of

ILI data;

b. pipeline repair and maintenance, including, but not limited to,

assessment and repair of internal and external defects, and aboveground pipeline

repairs;

c. the analysis and selection of measures to prevent and mitigate

threats to pipeline facilities, including but not limited to, the use of cleaning pigs,

the selection of corrosion inhibitors and inhibitor injection locations, methods of

assessing the effectiveness of inhibitors in liquid hydrocarbon pipelines in general

and in Arctic environments;

d. the development and implementation of risk models, the use of risk

modeling software, and the assessment of the effectiveness of such models and

software;

e. the principles and use of non-ILI assessment methods and tools for

pipelines including, at a minimum, guided wave, real time radiography, and

ultrasound techniques; and


30

f. the operation of liquid hydrocarbon pipeline systems including

injection of water and gas for enhanced recovery, well and flow lines and

gathering systems, and analysis of products, e.g., to ensure contract limits are not

exceeded.

32. No proposed consultant shall be a present or former BPXA employee or

contractor or the present employee of any contractor of BPXA. Within thirty (30) Days of

receiving the list of proposed consultants, the United States shall approve or disapprove

each member of the list, and approval shall not be unreasonably withheld. If the United

States disapproves of all of the proposed consultants on BPXA’s list, then BPXA shall

submit another list of proposed contractors to the United States within thirty (30) Days of

receipt of written notice disapproving of the contractors on the previous list. Within

thirty (30) Days of United States’ ultimate approval of one or more proposed consultants,

BPXA shall select a proposed consultant from those approved by the United States and

shall enter into the contract described in Paragraphs 30 and 31, above. If the

consultant(s) approved by the United States are no longer available or willing to accept

the work described in Paragraph 33 when notified of their selection by BPXA, then

BPXA shall select another consultant approved by the United States and enter into the

contract described in Paragraphs 30 and 31 within thirty (30) Days.

33. Duties of the Independent Monitoring Contractor. BPXA’s contract with the IMC

shall require the IMC to perform the following duties:

a. Review and analyze all information submitted (via the Electronic

Portal or by other means) and work performed by BPXA, and any other data,


31

information or other materials requested of BPXA, pursuant to the requirements

of this Decree, and assess whether such information and work is complete and

whether BPXA is complying with the requirements of this Decree.

b. Conduct and present to the United States all analyses and

recommendations independently of any suggestions or conclusions of BPXA.

c. Notify the United States and BPXA in writing within ten (10) Days

of discovery of any potential non-compliance with the requirements of this

Decree.

d. Notify the United States and BPXA orally or by electronic or

facsimile transmission within twenty four (24) hours of any immediate conditions

that BPXA has not investigated or repaired within the timeframes set out in

Appendix C, Actionable Anomaly Criteria, Investigation and Mitigation Time

Frames.

e. Prepare and submit to the United States and BPXA a quarterly

report that, at a minimum, contains the information, and is organized, as provided

in the Sample quarterly IMC Report attached as Appendix G to this Decree. The

first quarterly report is due no later than three months after the Effective Date,

and each quarterly report shall be submitted every three (3) months thereafter

until termination of this Decree pursuant to Section XVII.

f. BPXA’s contract with the IMC shall require the IMC not to seek

work from BPXA while it performs duties pursuant to the Consent Decree.


32

34. Replacement Procedure. If the IMC becomes unable or unwilling to perform or

complete the duties described in Paragraph 33, BPXA and the United States shall confer

in good faith on whether BPXA and the United States need to select a replacement IMC.

If BPXA and the United States agree on the need to replace the IMC, BPXA and the

United States shall select the replacement IMC in accordance with the selection

procedures in Paragraph 31 of this Decree. If BPXA and the United States do not agree

on the need to replace the IMC, any party may invoke the dispute resolution procedures

in Section IX of this Decree.

35. Neither Defendant nor the United States shall be bound by the statements,

conclusions, or opinions of the IMC. However, if Defendant violates any requirement of

this Decree, Defendant shall be liable for stipulated penalties to the United States,

pursuant to Section VII (Stipulated Penalties), regardless of the statements, conclusions

or opinions of the IMC.

VI. REPORTING, RECORDKEEPING, AND ELECTRONIC PORTAL REQUIREMENTS

36. Electronic Portal. Within sixty (60) Days of the Effective Date, BPXA shall

provide the United States access via an Electronic Portal (Portal) to assist the United

States in monitoring compliance with this Decree. All documents, certifications, plans,

reports, updates, notices, procedures or other information (Materials) that are required

pursuant to this Decree shall be made available to the United States and the IMC via a

secure, web-based Portal. The Portal shall: be easily navigable, include links to all

Materials in electronic format, allow users to save and print Materials, be clearly

organized and indexed according to the Sections and Paragraphs of this Decree, and


33

accessible 24 hours per day. The Portal shall also provide access to BPXA’s GIS,

including all data overlay functions and defect locations. All Materials shall remain

available through the Portal until termination of this Decree in accordance with Section

XVII (Termination). Defendant may assert that information made available to the United

States via the portal is protected as Confidential Business Information (CBI) as set out in

Paragraph 81 below.

37. Regular Reporting. BPXA shall report to the United States on the status of all

actions required under Section V (Compliance Requirements) of this Consent Decree.

The first report shall be due six months from the Effective Date. Subsequent reports

shall be provided to the United States on or before March 31st of each year for the

previous calendar year and continuing through Termination of this Consent Decree.

Each report shall include a progress report regarding:

a. the Data and Information Collection Element plans and procedures that

have been developed, submitted for approval, and implemented and all other

specified information submitted and tasks conducted, as required by Paragraph 20

in Section V of this Decree;

b. the requirement that Pipeline System pipelines are inspected and required

documentation is prepared, and provide the most current inspection schedule and

all other information as required by Paragraph 21 in Section V of this Decree;

c. the requirement that the Risk Ranking Procedure be prepared, submitted

for approval, and implemented; the Risk Ranking be conducted and revised

annually, and provide the most current Risk Ranking Report as required by


34

Paragraph 22 in Section V of this Decree;

d. the requirement that a functional GIS be completed, demonstrated to the

United States, made accessible to the United States and the IMC, and that GIS

training be provided to BPXA employees and agents, as required by Paragraph 23

in Section V of this Decree;

e. the requirement that a Risk Prevention and Mitigation procedure be

developed and implemented, prevention and mitigation measures be reviewed,

their effectiveness assessed and changes made as necessary, and all other

specified information be provided and tasks be conducted, as required by

Paragraph 24 in Section V of this Decree;

f. the requirement that repairs be conducted, and provide the most current

repair schedule, a list of repairs made to date, and all other specific information be

provided and tasks be conducted as required by Paragraph 25 in Section V of this

Decree;

g. the requirement that a procedure for continual program improvement be

developed and implemented, and a list of BPXA personnel responsible for

implementing this element and a detailed explanation of program improvement

activities be provided, as required by Paragraph 26 in Section V of this Decree;

h. the leak detection activities, as required by Paragraphs 27-29 in Section V

of this Decree; and


35

i. a list of all spills from the Pipeline System that are reportable under the

Clean Water Act. This portion of the report shall be in a form approved by the

United States, including the following information:

i. spill date;

ii. National Response Center identification number;

iii. narrative description of spill location;

iv. from what piece of equipment the spill occurred;

v. spill material and quantity spilled;

vi. quantity recovered;

vii. cause of spill, if known;

viii. description of actions taken or planned to address spill cause and

help prevent future spills from similar causes; and

ix. description of any environmental impacts from the spill.

38. All reports shall be posted on the Electronic Portal and submitted to the IMC and

the persons designated in Section XIII of this Decree (Notices).

39. Notification Requirements. If Defendant violates, or has reason to believe that it

may violate, any requirement of this Consent Decree, Defendant shall notify the United

States of such violation and its likely duration, in writing, within ten (10) working Days

of the Day Defendant first becomes aware of the violation, with an explanation of the

violation’s likely cause and of the remedial steps taken, or to be taken, to prevent or

minimize such violation. If the cause of a violation cannot be fully explained at the time

of the notification, Defendant shall so state in the report. Defendant shall investigate the


36

cause of the violation and submit an explanation of the cause of the violation, within

thirty (30) Days of the Day Defendant becomes aware of the cause of the violation.

Nothing in this Paragraph or the following Paragraph relieves Defendant of its obligation

to provide the notice required by Section VIII of this Consent Decree (Force Majeure).

40. Whenever any violation of this Consent Decree or any other event affecting

Defendant’s performance under this Decree may pose an immediate threat to the public

health or welfare or the environment, Defendant shall notify the United States orally or

by electronic or facsimile transmission as soon as possible, but no later than 48 hours

after Defendant first knew of the violation or event. This procedure is in addition to the

requirements set forth in the preceding Paragraph.

41. Each written report and Notification of Noncompliance submitted by Defendant

under this Section shall be signed by an official of the submitting party and include the

following certification:

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

This certification requirement does not apply to emergency or similar notifications where

compliance would be impractical.


37

42. BPXA shall provide to the United States certification that all remedial measures

required by Section V have been completed no later than August 31, 2015.

43. The reporting requirements of this Consent Decree do not relieve Defendant of

any reporting obligations required by the Clean Water Act, Clean Air Act, Federal

Pipeline Safety Laws, or implementing regulations, or by any other federal, state, or local

law, regulation, permit, or other requirement.

44. Subject to the Confidentiality provisions of Paragraph 81 set out below,

information provided to the United States pursuant to this Consent Decree may be used

by the United States in any proceeding to enforce the provisions of this Consent Decree

and as otherwise permitted by law.

45. Approval of Deliverables. After review of any plan, report, or other item that is

required to be submitted for approval pursuant to this Consent Decree, the United States

shall, in writing: (a) approve the submission; (b) approve the submission upon specified

conditions; (c) approve part of the submission and disapprove the remainder; or (d)

disapprove the submission. A disapproval under (c) or (d) of this Paragraph shall set

forth the reasons for the deficiency in sufficient detail to allow Defendant to correct the

deficiencies.

46. If the submission is approved pursuant to Paragraph 45(a), Defendant shall take

all actions required by the plan, report, or other document, in accordance with the

schedules and requirements of the plan, report, or other document, as approved. If the

submission is conditionally approved or approved only in part, pursuant to Paragraph

45(b) or 45(c), Defendant shall, upon written direction from the United States, take all


38

actions required by the approved plan, report, or other item that the United States

determines is technically severable from any disapproved portions, subject to

Defendant’s right to dispute only the specified conditions or the disapproved portions,

under Section IX of this Decree (Dispute Resolution).

47. If the submission is disapproved in whole or in part pursuant to Paragraph 45(c)

or 45(d), Defendant shall, within 30 Days or such other time as the Parties agree to in

writing, correct all deficiencies and resubmit the plan, report, or other item, or

disapproved portion thereof, for approval, in accordance with the preceding Paragraphs.

If the resubmission is approved in whole or in part, Defendant shall proceed in

accordance with the preceding Paragraph.

48. Any stipulated penalties applicable to the original submission, as provided in

Section VII of this Decree, shall accrue during the 30-Day period or other specified

period, but shall not be payable unless the resubmission is untimely or is disapproved in

whole or in part; provided that, if the original submission was so deficient as to constitute

a material breach of Defendant’s obligations under this Decree, the stipulated penalties

applicable to the original submission shall be due and payable notwithstanding any

subsequent resubmission.

49. If a resubmitted plan, report, or other item, or portion thereof, is disapproved in

whole or in part, the United States may again require Defendant to correct any

deficiencies, in accordance with the preceding Paragraphs, or may itself correct any

deficiencies, subject to Defendant’s right to invoke Dispute Resolution and the right of

the United States to seek stipulated penalties as provided in the preceding Paragraphs.


39

50. Permits. Where any compliance obligation under this Section requires Defendant

to obtain a federal, state, or local permit or approval, Defendant shall submit timely and

complete applications and take all other actions necessary to obtain all such permits or

approvals. Defendant may seek relief under the provisions of Section VIII of this

Consent Decree (Force Majeure) for any delay in the performance of any such obligation

resulting from a failure to obtain, or a delay in obtaining, any permit or approval required

to fulfill such obligation, if Defendant has submitted timely and complete applications

and has taken all other actions necessary to obtain all such permits or approvals.

VII. STIPULATED PENALTIES

51. Defendant shall be liable for stipulated penalties to the United States for

violations of this Consent Decree as specified below, unless excused under Section VIII

(Force Majeure). A violation includes failing to perform any obligation required by the

terms of this Decree, including any work plan or schedule approved under this Decree,

according to all applicable requirements of this Decree and within the specified time

schedules established by or approved under this Decree.

52. Late Payment of Civil Penalty. If Defendant fails to pay the civil penalty required

to be paid under Section IV (Civil Penalty) when due, Defendant shall pay a stipulated

penalty of $2,500 per Day for each Day that the payment is late.

53. Compliance Milestones

a. The following stipulated penalties shall accrue per violation per

Day for each violation of the requirements (both substantive requirements

and scheduling requirements) identified in subparagraph b, below:


40

Penalty Per Violation Per Day Period of Noncompliance

$750 1st through 14th Day

$1000 15th through 30th Day

$1500 31st Day and beyond

b. Failure to comply with the requirements in this Consent Decree

other than the reporting requirements specified in Paragraph 54 below. These

requirements include but are not limited to the following obligations under this

Decree:

i. Failing to obtain and maintain emergency repair materials

in compliance with Paragraph 15;

ii. Failing to amend its asbestos training course and materials

in compliance with Paragraphs 17 and 18;

iii. Failing to implement each and every Element of the

Pipeline System-Wide Integrity Management Program in compliance with

Paragraphs 20-26;

iv. Failing to evaluate the LEOS and ATMOS Pilot Projects in

comparison to new leak detection technologies in compliance with

Paragraphs 27-29; and

v. Failing to hire or replace an IMC in compliance with

Paragraphs 30 through 34.


41

54. Reporting Requirements. The following stipulated penalties shall accrue per

violation per Day for each violation of the reporting requirements of Section VI of this

Consent Decree:

Penalty Per Violation Per Day Period of Noncompliance

$1000 1st through 14th Day

$1750 15th through 30th Day

$2500 31st Day and beyond

55. Stipulated penalties under this Section shall begin to accrue on the Day after

performance is due or on the Day a violation occurs, whichever is applicable, and shall

continue to accrue until performance is satisfactorily completed or until the violation

ceases. Stipulated penalties shall accrue simultaneously for separate violations of this

Consent Decree.

56. Defendant shall pay any stipulated penalty within thirty (30) Days of receiving

the United States’ written demand.

57. The United States may, in the unreviewable exercise of its discretion, reduce or

waive stipulated penalties otherwise due it under this Consent Decree.

58. Stipulated penalties shall continue to accrue as provided in Paragraph 55 during

any Dispute Resolution, but need not be paid until the following:

a. If the dispute is resolved by agreement or by a decision of the United

States that is not appealed to the Court, Defendant shall pay accrued penalties

determined to be owing, together with interest, to the United States within 30


42

Days of the Effective Date of the agreement or the receipt of the United States’

decision or order.

b. If the dispute is appealed to the Court, stipulated penalties shall cease to

accrue on the 31st Day after the Court’s receipt of the final submission regarding

the dispute until the date that the Court issues a final decision regarding such

dispute. If the United States prevails, Defendant shall pay all accrued penalties

determined by the Court to be owing, together with interest, within 60 Days of

receiving the Court’s decision or order, except as provided in subparagraph (c),

below. If the Defendant prevails, no accrued penalties, interest, or stipulated

penalties associated with the subject of the dispute shall be due.

c. If any Party appeals the District Court’s decision, Defendant shall pay all

accrued penalties determined by the appellate court to be owing, together with

interest, within fifteen (15) Days of receiving the final appellate court decision.

59. Defendant shall pay stipulated penalties owing to the United States in the manner

set forth and with the confirmation notices required by Paragraph 9, except that the

transmittal letter shall state that the payment is for stipulated penalties and shall state for

which violation(s) the penalties are being paid.

60. If Defendant fails to pay stipulated penalties according to the terms of this

Consent Decree, Defendant shall be liable for interest on such penalties, as provided for

in 28 U.S.C.1961, accruing as of the date payment became due. Nothing in this

Paragraph shall be construed to limit the United States from seeking any remedy

otherwise provided by law for Defendant’s failure to pay any stipulated penalties.


43

61. Subject to the provisions of Section XI of this Consent Decree (Effect of

Settlement/Reservation of Rights), the stipulated penalties provided for in this Consent

Decree shall be in addition to any other rights, remedies, or sanctions available to the

United States for Defendant’s violation of this Consent Decree or applicable law. Where

a violation of this Consent Decree is also a violation of the Clean Water Act, Clean Air

Act, Federal Pipeline Safety Laws, or implementing regulations, Defendant shall be

allowed a credit, for any stipulated penalties paid, against any statutory penalties imposed

for such violation.

VIII. FORCE MAJEURE

62. “Force majeure” for purposes of this Consent Decree, is defined as any event

arising from causes beyond the control of Defendant, of any entity controlled by

Defendant, or of Defendant’s contractors, that delays or prevents the performance of any

obligation under this Consent Decree despite Defendant’s reasonable efforts to fulfill the

obligation. The requirement that Defendant exercise reasonable efforts to fulfill the

obligation includes using reasonable efforts to anticipate any potential Force Majeure

event and reasonable efforts to address the effects of any such event (a) as it is occurring

and (b) after it has occurred to prevent or minimize any resulting delay to the greatest

extent possible. A “Force Majeure” event does not include Defendant’s financial

inability to perform any obligation under this Consent Decree.

63. If any event occurs or has occurred that may delay the performance of any

obligation under this Consent Decree, whether or not caused by a force majeure event,

Defendant shall provide notice orally or by electronic or facsimile transmission to the


44

United States, within 72 hours of when Defendant first knew that the event might cause a

delay. Within seven Days thereafter, Defendant shall provide in writing to the United

States an explanation and description of the reasons for the delay; the anticipated

duration of the delay; all actions taken or to be taken to prevent or minimize the delay; a

schedule for implementation of any measures to be taken to prevent or mitigate the delay

or the effect of the delay; Defendant’s rationale for attributing such delay to a force

majeure event if it intends to assert such a claim; and a statement as to whether, in the

opinion of Defendant, such event may cause or contribute to an endangerment to public

health, welfare or the environment. Defendant shall include with any notice all available

documentation supporting the claim that the delay was attributable to a force majeure.

Failure to comply with the above requirements shall preclude Defendant from asserting

any claim of force majeure for that event for the period of time of such failure to comply,

and for any additional delay caused by such failure. Defendant shall be deemed to know

of any circumstance of which Defendant, any entity controlled by Defendant, or

Defendant’s contractors knew or should have known.

64. In response to Defendant’s written notice in paragraph 63, the United States shall

make a determination whether it agrees or disagrees that a force majeure event has

occurred, and, pursuant to Section XIII (Notices) of this Consent Decree, provide written

notice to Defendant of its determination and the reasoning for that decision.

65. If the United States agrees that the delay or anticipated delay is attributable to a

force majeure event, the time for performance of the obligations under this Consent

Decree that are affected by the force majeure event will be extended by the United States


45

for such time as is necessary to complete those obligations. An extension of the time for

performance of the obligations affected by the force majeure event shall not, of itself,

extend the time for performance of any other obligation unless the United States, or the

Court, determines that dependant activities will be delayed by the force majeure and that

the time period should be extended for performance of such activities. The United States

will notify Defendant in writing of the length of the extension, if any, for performance of

the obligations affected by the force majeure event.

66. If the United States does not agree that the delay or anticipated delay has been or

will be caused by a force majeure event, the United States will notify Defendant in

writing of its decision, as soon as is reasonably practicable.

67. If Defendant elects to invoke the dispute resolution procedures set forth in Section

IX (Dispute Resolution), it shall do so no later than 15 Days after receipt of the United

States’ notice. In any such proceeding, Defendant shall have the burden of

demonstrating by a preponderance of the evidence that the delay or anticipated delay has

been or will be caused by a force majeure event, that the duration of the delay or the

extension sought was or will be warranted under the circumstances, that best efforts were

exercised to avoid and mitigate the effects of the delay, and that Defendant complied with

the requirements of Paragraphs 62 and 63, above.

IX. DISPUTE RESOLUTION

68. Unless otherwise expressly provided for in this Consent Decree, the dispute

resolution procedures of this Section shall be the exclusive mechanism to resolve

disputes arising under or with respect to this Consent Decree. Defendant’s failure to seek


46

resolution of a dispute under this Section shall preclude Defendant from raising any such

issue as a defense to an action by the United States to enforce any obligation of

Defendant arising under this Decree.

69. Informal Dispute Resolution. Any dispute subject to Dispute Resolution under

this Consent Decree shall first be the subject of informal negotiations. The dispute shall

be considered to have arisen when Defendant sends the United States a written Notice of

Dispute. Such Notice of Dispute shall state clearly the matter in dispute. The period of

informal negotiations shall not exceed 30 Days from the date the dispute arises, unless

that period is modified by written agreement. For informal disputes, the Branch Chief of

the relevant program office within EPA Region 10 shall, on the record, make the final

determination for issues involving EPA and the Regional Director, PHMSA Western

Region shall, on the record, make the final determination for issues involving DOT. If

the Parties cannot resolve a dispute by informal negotiations, then the position advanced

by the United States shall be considered binding unless, within thirty (30) Days after the

conclusion of the informal negotiation period, Defendant invokes formal dispute

resolution procedures as set forth below.

70. Formal Dispute Resolution. Defendant shall invoke formal dispute resolution

procedures, within the time period provided in the preceding Paragraph, by serving on

the United States a written Statement of Position regarding the matter in dispute. The

Statement of Position shall include, but need not be limited to, any factual data, analysis,

or opinion supporting Defendant’s position and any supporting documentation relied

upon by Defendant.


47

71. The United States shall serve its Statement of Position within forty-five (45) Days

of receipt of Defendant’s Statement of Position. The United States’ Statement of

Position shall include, but need not be limited to, any factual data, analysis, or opinion

supporting that position and any supporting documentation relied upon by the United

States. The United States’ Statement of Position shall be binding on Defendant, unless

Defendant files a motion for judicial review of the dispute in accordance with the

following Paragraph.

72. Defendant may seek judicial review of the dispute by filing with the Court and

serving on the United States, in accordance with Section XIII of this Consent Decree

(Notices), a motion requesting judicial resolution of the dispute. The motion must be

filed within 10 Days of receipt of the United States’ Statement of Position pursuant to the

preceding Paragraph. The motion shall contain a written statement of Defendant’s

position on the matter in dispute, including any supporting factual data, analysis, opinion,

or documentation, and shall set forth the relief requested and any schedule within which

the dispute must be resolved for orderly implementation of the Consent Decree.

73. The United States shall respond to Defendant’s motion within the time period

allowed by the Local Rules of this Court. Defendant may file a reply memorandum, to

the extent permitted by the Local Rules.

74. Standard of Review. In any dispute brought under Paragraph 70, Defendant shall

bear the burden of demonstrating that its position complies with this Consent Decree and

that Defendant is entitled to relief under applicable principles of law.


48

75. The invocation of dispute resolution procedures under this Section shall not, by

itself, extend, postpone, or affect in any way any obligation of Defendant under this

Consent Decree, unless and until final resolution of the dispute so provides. Except as

otherwise provided in this Consent decree, stipulated penalties with respect to the

disputed matter shall continue to accrue from the first Day of noncompliance, but

payment shall be stayed pending resolution of the dispute as provided in Paragraph 58. If

Defendant does not prevail on the disputed issue, stipulated penalties shall be assessed

and paid as provided in Section VII (Stipulated Penalties).

X. INFORMATION COLLECTION AND RETENTION

76. The United States and its representatives, including attorneys, contractors, and

consultants, shall have the right of entry into any facility covered by this Consent Decree,

at all reasonable times, upon presentation of credentials, to:

a. monitor the progress of activities required under this Consent

Decree;

b. verify any data or information submitted to the United States in

accordance with the terms of this Consent Decree;

c. obtain samples and, upon request, splits of any samples taken by

Defendant or its representatives, contractors, or consultants;

d. obtain documentary evidence, including photographs and similar

data; and

e. assess Defendant’s compliance with this Consent Decree.


49

77. The right to entry does not replace the United States’ existing access, entry, and

information gathering authority.

78. Upon request, Defendant shall provide the United States or its authorized

representatives splits of any samples taken by Defendant. Defendant shall bear any costs.

Upon request, the United States shall provide Defendant splits of any samples taken by

the United States. Defendant shall provide appropriate containers for the samples upon

request.

79. Until five years after the termination of this Consent Decree, Defendant shall

retain, and shall instruct its contractors and agents to preserve, all non-identical copies of

all documents, records, or other information (including documents, records, or other

information in electronic form) in its or its contractors’ or agents’ possession or control,

or that come into its or its contractors’ or agents’ possession or control, and that relate in

any manner to Defendant’s performance of its obligations under this Consent Decree.

This information-retention requirement shall apply regardless of any contrary corporate

or institutional policies or procedures. At any time during this information-retention

period, upon request by the United States, Defendant shall provide copies of any

documents, records, or other information required to be maintained under this Paragraph.

80. At the conclusion of the information-retention period provided in the preceding

Paragraph, Defendant shall notify the United States at least 90 Days prior to the

destruction of any documents, records, or other information subject to the requirements

of the preceding Paragraph and, upon request by the United States, Defendant shall

deliver any such documents, records, or other information to the requested U.S. agency.


50

Defendant may assert that certain documents, records, or other information is privileged

under the attorney-client privilege or any other privilege recognized by federal law. If

Defendant asserts such a privilege, it shall provide the following: (1) the title of the

document, record, or information; (2) the date of the document, record, or information;

(3) the name and title of each author of the document, record, or information; (4) the

name and title of each addressee and recipient; (5) a description of the subject of the

document, record, or information; and (6) the privilege asserted by Defendant. However,

no documents, records, or other information created or generated pursuant to the

requirements of this Consent Decree shall be withheld on grounds of privilege.

81. Defendant may also assert that information required to be provided to the United

States under this Consent Decree, including via the electronic portal, is protected as

Confidential Business Information (CBI) under 40 C.F.R. Part 2 or 49 C.F.R. Part 7. As

to any information that Defendant seeks to protect as CBI, Defendant shall follow the

procedures set forth in 40 C.F.R. Part 2 and 49 C.F.R. Part 7.

82. This Consent Decree in no way limits or affects any right of entry and inspection,

or any right to obtain information, held by the United States pursuant to applicable laws,

regulations, or permits, nor does it limit or affect any duty or obligation of Defendant to

maintain documents, records, or other information imposed by applicable federal or state

laws, regulations, or permits.


51

XI. EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS

83. This Consent Decree resolves the civil claims of the United States against

Defendant for the violations alleged in the Complaint filed in this action through the date

of lodging.

84. The United States reserves all legal and equitable remedies available to enforce

the provisions of this Consent Decree, except as expressly stated in Paragraph 83. This

Consent Decree shall not be construed to limit the rights of the United States to obtain

penalties or injunctive relief under Clean Water Act, Clean Air Act, Federal Pipeline

Safety Laws, or implementing regulations, or under other federal laws, regulations, or

permit conditions, except as expressly specified in Paragraph 83.

85. In any subsequent administrative or judicial proceeding initiated by the United

States for injunctive relief, civil penalties, other appropriate relief relating to the

Defendant’s violations, Defendant shall not assert, and may not maintain, any defense or

claim based upon the principles of waiver, res judicata, collateral estoppel, issue

preclusion, claim preclusion, claim-splitting, or other defenses based upon any contention

that the claims raised by the United States in the subsequent proceeding were or should

have been brought in the instant case, except with respect to claims that have been

specifically resolved pursuant to Paragraph 83 of this Section.

86. This Consent Decree does not limit or affect the rights of Defendant or of the

United States against anyone who is not a party to this Consent Decree, nor does it limit

the rights of anyone who is not a party to this Consent Decree, against Defendant, except

as otherwise provided by law.


52

87. This Consent Decree shall not be construed to create rights in, or grant any cause

of action to, any third party not party to this Consent Decree.

88. Defendant hereby covenants not to sue and agrees not to assert any claim against

the United States pursuant to the Clean Water Act or any other federal law, state law, or

regulation, including, but not limited to, any direct or indirect claim for reimbursement

from the Oil Spill Liability Trust Fund for any matter related to the violations alleged in

the Complaint filed in this action, or related to response activities.

89. This Consent Decree is without prejudice to the rights of the United States against

Defendant with respect to all matters other than those expressly specified in Paragraph 83

above, including, but not limited to, the following:

a. claims based on a failure of Defendants to meet a requirement of

this Consent Decree;

b. criminal liability;

c. liability for past, present, or future discharges of oil other than

those expressly resolved herein;

d. reimbursement to the federal Oil Spill Liability Trust Fund for any

disbursements arising from the spills alleged in the Complaint or any other related

incident, including claims for subrogated claims pursuant to Section 1015 of the

Oil Pollution Act, 33 U.S.C. § 2715; and

e. liability for damages for injury to, or loss of natural resources, and

for the cost of any natural resource damage assessments.


53

XII. COSTS

90. The Parties shall bear their own costs of this action, including attorneys’ fees,

except that the United States shall be entitled to collect the costs (including attorneys’

fees) incurred in any action necessary to collect any portion of the civil penalty or any

stipulated penalties due but not paid by Defendant.

XIII. NOTICES

91. Unless otherwise specified herein, whenever notifications, submissions, or

communications are required by this Consent Decree, they shall be made in writing and

addressed as follows:

To the United States: Chief, Environmental Enforcement Section Environment and Natural Resources Division U.S. Department of Justice Box 7611 Ben Franklin Station Washington, D.C. 20044-7611 Re: DOJ No. 90-5-1-1-08808 and Director of Enforcement U.S. Environmental Protection Agency Region 10 1200 Sixth Avenue Seattle, WA 98101 and Regional Counsel U.S. Environmental Protection Agency Region 10 1200 Sixth Avenue Seattle, WA 98101


54

and Office of the Chief Counsel Pipeline and Hazardous Materials Safety Administration Department of Transportation East Building, 2nd Floor 1200 New Jersey Avenue SE Washington, DC 20590 and Director, Western Region Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration 12300 W. Dakota Ave Suite 110 Lakewood, CO 80228 and Deputy Region Director, Western Region Office of Pipeline Safety Pipeline and Hazardous Materials Safety Administration 188 West Northern Lights Blvd., Suite 520 Anchorage, AK 99503 To Defendant: Vice President of Operations BP Exploration (Alaska) Inc. PO Box 196612 900 East Benson Blvd Anchorage, AK 99519-6612 and Managing Attorney BP Exploration (Alaska) Inc. PO Box 196612 900 East Benson Blvd Anchorage, AK 99519-6612


55

92. Any Party may, by written notice to the other Parties, change its designated notice

recipient or notice address provided above.

93. Notices submitted pursuant to this Section shall be deemed submitted upon

mailing, unless otherwise provided in this Consent Decree or by mutual agreement of the

Parties in writing.

XIV. EFFECTIVE DATE

94. The Effective Date of this Consent Decree shall be the date upon which this

Consent Decree is entered by the Court or a motion to enter the Consent Decree is

granted, whichever occurs first, as recorded on the Court’s docket.

XV. RETENTION OF JURISDICTION

95. The Court shall retain jurisdiction over this case until termination of this Consent

Decree, for the purpose of resolving disputes arising under this Decree or entering orders

modifying this Decree, pursuant to Sections IX and XVI, or effectuating or enforcing

compliance with the terms of this Decree.

XVI. MODIFICATION

96. The terms of this Consent Decree, including any attached appendices, may be

modified only by a subsequent written agreement signed by all the Parties. Where the

modification constitutes a material change to this Decree, it shall be effective only upon

approval by the Court.

97. Any disputes concerning modification of this Decree shall be resolved pursuant to

Section IX of this Decree (Dispute Resolution), provided, however, that, instead of the

burden of proof provided by Paragraph 74, the Party seeking the modification bears the


56

burden of demonstrating that it is entitled to the requested modification in accordance

with Federal Rule of Civil Procedure 60(b).

XVII. TERMINATION

98. After Defendant has completed the requirements of Section V (Compliance

Requirements) of this Decree, has paid the civil penalty and any accrued stipulated

penalties as required by this Consent Decree, and no sooner than three (3) years after the

Effective Date, Defendant may serve upon the United States a Request for Termination,

stating that Defendant has satisfied those requirements, together with all necessary

supporting documentation.

99. Following receipt by the United States of Defendant’s Request for Termination,

the Parties shall confer informally concerning the Request and any disagreement that the

Parties may have as to whether Defendant has satisfactorily complied with the

requirements for termination of this Consent Decree. If the United States agrees that the

Decree may be terminated, the Parties shall submit, for the Court’s approval, a joint

stipulation terminating the Decree.

100. If the United States does not agree that the Decree may be terminated, Defendant

may invoke Dispute Resolution under Section IX of this Decree. However, Defendant

shall not seek Dispute Resolution of any dispute regarding termination, under Paragraph

70 of Section IX, until sixty (60) days after service of its Request for Termination.

101. Nothing in this Consent Decree prevents Defendant from completing any of the

obligations earlier than the deadlines provided for herein.


57

XVIII. PUBLIC PARTICIPATION

102. This Consent Decree shall be lodged with the Court for a period of not less than

30 Days for public notice and comment in accordance with 28 C.F.R. 50.7. The United

States reserves the right to withdraw or withhold its consent if the comments regarding

the Consent Decree disclose facts or considerations indicating that the Consent Decree is

inappropriate, improper, or inadequate. Defendant consents to entry of this Consent

Decree without further notice and agrees not to withdraw from or oppose entry of this

Consent Decree by the Court or to challenge any provision of the Decree, unless the

United States has notified Defendant in writing that it no longer supports entry of the

Decree.

XIX. SIGNATORIES/SERVICE

103. Each undersigned representative of Defendant and the Assistant Attorney General

for the Environment and Natural Resources Division of the Department of Justice

certifies that he or she is fully authorized to enter into the terms and conditions of this

Consent Decree and to execute and legally bind the Party he or she represents to this

document.

104. This Consent Decree may be signed in counterparts, and its validity shall not be

challenged on that basis. Defendant agrees to accept service of process by mail with

respect to all matters arising under or relating to this Consent Decree and to waive the

formal service requirements set forth in Rules 4 and 5 of the Federal Rules of Civil

Procedure and any applicable Local Rules of this Court including, but not limited to,

service of a summons.


58

XX. INTEGRATION

105. This Consent Decree constitutes the final, complete, and exclusive agreement and

understanding among the Parties with respect to the settlement embodied in the Decree

and supersedes all prior agreements and understandings, whether oral or written,

concerning the settlement embodied herein. Other than deliverables that are

subsequently submitted and approved pursuant to this Decree, no other document, nor

any representation, inducement, agreement, understanding, or promise, constitutes any

part of this Decree or the settlement it represents, nor shall it be used in construing the

terms of this Decree.

XXI. FINAL JUDGMENT

106. Upon approval and entry of this Consent Decree by the Court, this Consent

Decree shall constitute a final judgment of the Court as to the United States and

Defendant.

XXII. APPENDICES

107. The following appendices are attached to and part of this Consent Decree:

Appendix A is the Pipeline System Maps and Lists of Flow Lines, Well Lines,

and Produced Water Lines;

Appendix B is the List of Emergency Repair Equipment and Materials;

Appendix C is the Actionable Anomaly Criteria, Investigation and Mitigation

Time Frames;

Appendix D is the Pipeline Inspection Frequency Chart;

Appendix E is the Corrosion Monitoring Device Requirements;

Appendix F is the Leak Detection Technology Assessment Criteria; and


Appendix G is the Quarterly IMC Report Template.

DATEDANDENTEREDthis20th day of -July, 2011.

Is! HONORABLE JOHN W. SEDWICK UNITED STATES DISTRICT JUDGE

Signatures of the individuals representing the parties are on the consent decree filed at docket 40-2.

59


60

FOR THE UNITED STATES OF AMERICA, in U.S. v. BPXA, Inc., Civil No. 3:09-cv-00064-JWS (D. Alaska): ___________ ___________________________ Date IGNACIA S. MORENO Assistant Attorney General Environment and Natural Resources Division U.S. Department of Justice

_________________________________ KATHERINE A. LOYD

Trial Attorney Environmental Enforcement Section Environment and Natural Resources Division U.S. Department of Justice 999 18th Street

South Terrace – Suite 370 Denver, CO 80202


61

FOR THE U.S. ENVIRONMENTAL PROTECTION AGENCY in U.S. v. BPXA, Inc., Civil No. 3:09-cv-00064-JWS (D. Alaska): Date: ________________ _________________________________ CYNTHIA GILES Assistant Administrator

Office of Enforcement and Compliance Assurance

U.S. Environmental Protection Agency Date: ________________ ___________________________________ ADAM M. KUSHNER, Director Office of Civil Enforcement Office of Enforcement and Compliance Assurance U.S. Environmental Protection Agency 1200 Pennsylvania Ave., N.W. Washington, D.C. 20460 Date: _________________ ___________________________________ MARK POLLINS, Director Water Enforcement Division Office of Civil Enforcement Office of Enforcement and Compliance Assurance U.S. Environmental Protection Agency 1200 Pennsylvania Ave., N.W. Washington, D.C. 20460 Date: _________________ ___________________________________ GINNY PHILLIPS, Attorney Water Enforcement Division Office of Civil Enforcement Office of Enforcement and Compliance Assurance U.S. Environmental Protection Agency 1200 Pennsylvania Ave., N.W. Washington, D.C. 20460


62

FOR THE U.S. ENVIRONMENTAL PROTECTION AGENCY in U.S. v. BPXA, Inc., Civil No. 3:09-cv-00064-JWS (D. Alaska): Date: _____________ _____________________________ ALLYN L. STERN Regional Counsel U.S. Environmental Protection Agency Region 10 1200 Sixth Ave, Suite 900 Seattle, WA 98101 Date: ________________ ______________________________ STEPHANIE MAIRS Assistant Regional Counsel U.S. Environmental Protection Agency Region 10 1200 Sixth Ave, Suite 900 Seattle, WA 98101 Date: ________________ ______________________________ SHIRIN VENUS Assistant Regional Counsel U.S. Environmental Protection Agency Region 10 1200 Sixth Ave, Suite 900 Seattle, WA 98101


63

FOR THE U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION in U.S. v. BPXA, Inc., Civil No. 3:09-cv-00064-JWS (D. Alaska): __________ _________________________________ Date CYNTHIA QUARTERMAN Administrator Pipeline and Hazardous Materials Safety Administration U.S. Department of Transportation 1200 New Jersey Avenue, SE Washington, DC 20590 __________ _________________________________ Date JAMES M. PATES Assistant Chief Counsel for Pipeline Safety Office of Chief Counsel Pipeline and Hazardous Materials Safety Administration U.S. Department of Transportation 1200 New Jersey Avenue, SE Washington, DC 20590


64

FOR BP EXPLORATION (ALASKA) INC. in U.S. v. BPXA, Inc., Civil No. 3:09-cv-00064-JWS (D. Alaska): Date: _____________ _____________________________ BRUCE J. WILLIAMS Vice President, Operations BP Exploration (Alaska) Inc. 900 East Benson Blvd Anchorage, AK 99519 Date: ________________ ______________________________ RANDAL G. BUCKENDORF Chief Counsel BP Exploration (AK) Inc. 900 East Benson Blvd Seattle, WA 99519 Date: ________________ ______________________________ CAROL E. DINKINS Vinson & Elkins LLP First City Tower 1001 Fannin Street, Suite 2500 Houston, TX 77002


1

APPENDIX A Pipeline System Maps and Lists of Flow Lines, Well Lines, and Produced Water Lines


1

APPENDIX B

List of Emergency Repair Equipment and Materials

BPXA shall purchase, if not currently in stock, and maintain during the term of this Consent

Decree, 200 feet of pre-tested pipe, two sleeves four feet long, and one mechanical repair clamp

for each pipeline in the Pipeline System, which includes the following line sizes as of the

Effective Date of this Agreement: 12-inch; 14-inch; 16-inch: 18-inch; 20-inch; 24-inch; 28-inch;

30-inch; and 36-inch lines. Such inventory shall be maintained on the North Slope of Alaska.


1

APPENDIX C

Actionable Anomaly Criteria, Investigation and Mitigation Time Frames. The following chart describes Actionable Anomalies:

Conditions Requiring Follow-up

Required Time

Frame for Inspection

(from discovery)

Required Time

Frame for Repair (from

discovery) Immediate Conditions Metal loss > 80% of nominal wall (for rough tool tolerance inclusion, BPXA will perform field investigation to 70%).

5 days 5 days

Predicted Burst Pressure (Pburst) at the anomaly is less than the Maximum Operating Pressure (MOP).

5 days 5 days

Dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking of a stress riser.

5 days 5 days

Dent located on the top of the pipeline (above 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter.

5 days 5 days

An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.

5 days 5 days

60-day Conditions Dent located on the top of the pipeline (above the 4 and 8 o’clock positions) with a depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12).

30 days 60 days

A dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser.

30 days 60 days

180-day Conditions Dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld.

90 days 180 days

Dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a longitudinal seam weld.

90 days 180 days

Dent located on the top of the pipeline (above 4 and 8 o’clock position) with a depth greater than 2% of the pipelines diameter (0.250 inches in depth for a pipeline diameter less than NPS 12).

90 days 180 days


2

Conditions Requiring Follow-up

Required Time

Frame for Inspection

(from discovery)

Required Time

Frame for Repair (from

discovery) Dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline's diameter.

90 days 180 days

A calculation of the remaining strength of the pipe shows an operating pressure that is less than the current established maximum operating pressure (MOP) at the location of the anomaly.

90 days 180 days

An area of general corrosion with a predicted metal loss greater than 50% of nominal wall (to incorporate rough tool tolerances, BPXA will investigate to 40%).

90 days 180 days

Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline (to incorporate rough tool tolerances, BPXA will investigate to 40%).

90 days 180 days

Predicted metal loss greater than 50% of nominal wall that is in an area with widespread circumferential corrosion (to incorporate rough tool tolerances, BPXA will investigate to 40%).

90 days 180 days

Predicted metal loss greater than 50% of nominal wall that is located in an area that could affect a girth weld (to incorporate rough tool tolerances, BPXA will investigate to 40%).

90 days 180 days

Potential crack indication that when excavated is determined to be a crack.

90 days 180 days

Corrosion of or along a longitudinal seam weld. 90 days 180 days A gouge or groove greater than 12.5% of nominal wall. 90 days 180 days

The following tables show additional conditions and timeframes for repairs resulting from inspection data.

Intervention Criteria for Metal Loss Defects (Scheduled & Immediate)

Criteria Scheduled Intervention Condition

Immediate Intervention Condition

Minimum Thickness (Penetration - Thru

Wall)

Remaining wall is ≤ 0.100 but >0.050 and

where wall loss ≤80%

Remaining wall is ≤0.050-inch or wall loss is >80%

Safe Pressure(1) (Depth and Length -

Hoop Stress)

Safe Pressure(1) is ≥Established MAOP(2)

and ≤105% of Established

Safe Pressure(1) is <Established MAOP(2)


3

MAOP(2)

Circumferential Extent (Depth and Width -

Axial or Bending Stress)

Axial or Bending Stress exceeds Acceptable Limits(3) Pending Engineering Review

Notes:

1. Safe Pressure is the predicted remaining strength of a metal loss defect using Modified B31G 0.85-dL method in conjunction with a design factor, generally .72 for B31.4 lines and .72, .60, or .50 for B31.8 lines. As an example, applying .72 design factor to the B31G method results in a factor of safety equal to 1.39 (1/.72) or .72 of the predicted failure pressure.

2. MAOP is an acronym for Maximum Allowable Operating Pressure. MAOP, in this case, is the established maximum pressure at which the pipeline can safely operate under normal conditions.

3. Acceptable Limits for Circumferential Corrosion are theoretical solutions for determining the failure stress of a cylinder with a circumferential defect. Corrosion is acceptable if the actual effective corrosion depth and width is not greater than the allowable effective depth and width in accordance with the criteria for the given combination of pipe grade and design standard.

Options for Repair of Pipelines

Comply with ASME B31.4-2006 Table 451.6.2(b)-1 (w/notes).


1

APPENDIX D

Pipeline Inspection Frequency Chart

The following minimum inspection intervals shall be followed for each pipeline in the Pipeline

System, unless BPXA justifies the basis for, and the Parties agree upon a different inspection

interval.

Inspection Method

Aerial survey

• Remote pipelines (non-vehicle accessible) -

Once per calendar week

Vehicle /foot patrol • OTLs from production facilities to Skid 50

- Twice daily unless precluded by safety or

weather conditions.

• Pipelines on pads - during routine rounds

documented monthly.

• Cross country flow lines - daily

Corrosion Coupons Initially and typically 4 months but can range

to 1 year based on pipeline specific corrosion

data

ER probes Corrosion rate collected every 4 hours and

evaluated weekly. Probes replaced @ 75% of

probe life

Corrosion rate monitoring (CRM) sites Initially and typically 6 months but range from

1 week to 1 year based on results

ILI • Carbon Steel (CS) Pipelines in three phase

oil production with wall thickness of 0.312

or less and OTL pipelines - 3 years

• CS Pipelines in three phase oil production

with a wall thickness greater than 0.312 - 5


2

years

• CS Pipelines in produced water service

with a wall thickness of 0.375 inches or

less - 4 years

• CS Pipelines in produced water service

with a wall thickness of greater than 0.375

- 5 years

CP Testing Annually

River crossing survey Yearly and after significant flooding events

Pipeline Bridge inspections 5 years

Walking speed survey (VSMs, HSMs, etc.) Yearly on common carrier pipelines

5-years on all other pipelines


1

APPENDIX E Corrosion Monitoring Device Requirements1 Corrosion monitoring devices shall be positioned at the location in the optimal position to monitor the stream or fluid phase where corrosion is most severe. Location of Corrosion Monitoring Devices a. The monitoring device shall be located in the corrosive phase. Predictive models may be used to identify the most likely location for corrosion to occur in a given phase. The corrosive phase is almost always an aqueous phase. Therefore, monitoring devices shall be located at positions most likely to have the presence of water. Water holdup and water dropout effects are of central importance to device location. Water dropout is most likely in long horizontal pipe runs and less likely in vertical runs. If corrosion is expected to occur at the bottom of a horizontal line, the monitoring device shall be located in that position. If water condensation is expected, locating monitoring devices on top of the line shall also be considered. In fluid streams that have suspended solids, if the access fitting is located in positions between 3 o’clock and 9 o’clock, there is a risk of solids accumulating in the fitting. Accumulated solids can cause potential probe shielding problems or stuck probes. b. The anticipated corrosion mechanisms (e.g., general or localized attack, under deposit corrosion, erosion/corrosion) shall be considered. c. Effects of flow rate and flow regime shall be considered, including: 1. Probes and coupons should be sited in a region where water drop out is more likely and where hydrodynamics are uniform and representative of most of the system. 2. Access fittings shall be located a minimum distance of seven pipe diameters downstream and a minimum of three pipe diameters upstream of flow disturbances (e.g., bends, reducers, valves, orifice plates, thermowells) for the measurement to be representative of most of the system. In some cases, locating probes or coupons near a flow disturbance should be considered if these conditions are representative of a higher corrosion rate that is possible in the system. For example, water hold-up or flow induced corrosion may occur at an elbow. 3. If intrusive (not flush mounted) access fittings are installed in pairs, a minimum distance of 1 m (3 ft) shall be between each fitting. 4. If monitoring devices are intrusive and have a probe and a coupon holder, the probe shall be located in the upstream fitting to minimize turbulence around the second monitoring device.

1 Adapted from BP Corrosion Monitoring Procedure GP 06-70, Section 6.2.1.


2

5. If space limitations do not allow meeting the location criteria mentioned above, the hydrodynamic effects on corrosion rates shall be assessed. d. Chemical injection points shall be considered. Injection of production chemicals, including corrosion inhibitors, scale inhibitors, asphaltene and paraffin inhibitors, demulsifiers, oxygen scavengers, and biocides can have a marked effect on corrosion. 1. Corrosion monitoring devices shall be placed a minimum of five pipe diameters downstream of treatment chemical injection points. 2. Additional monitoring points upstream of production chemical injection shall be considered. Measuring corrosion rates before and after corrosion inhibitor injection is important in assessing its efficiency. Some production chemicals can be corrosive to certain steels and render corrosion inhibitors less effective if they are not fully compatible. e. Effects of process stream changes shall be considered. Changes in pressure, temperature, flow rate, inputs/outputs, etc, as well as position of equipment affecting process modify potential corrosivity of the fluids and preferred monitoring locations. f. Physical access shall not dictate monitoring locations. However, when a monitoring point is identified, the location should allow routine access for probe maintenance, retrieval, etc. g. Intrusive probes shall be located where they can remain in place for extended periods. h. Intrusive probes (not flush mounted) shall be installed upstream of any pig launcher or down stream of pig receivers. Otherwise, the probe requires retrieval prior to each pigging operation to avoid damage to the probe and the possibility of the pig becoming trapped. i. Practical factors limiting the choice of monitoring locations shall be considered. i. Coupons and probes require the line to be accessible for installation and service. ii. Fluid sampling may not be safe (e.g. pressures, temperatures) or reliable without contamination or blockage problems. iii. Adverse weather conditions or chance of vandalism may exclude the use of certain techniques in some locations. j. Corrosion monitoring locations shall be recorded on the relevant technical drawings. i. This should include P&IDs and isometric PFDs.


3

ii. On new facilities they should be included in the CAD system as this aids data analysis and the development of control procedures. iii. The records shall include: a) Details on the system, item and location b) Corrosion monitoring method. c) Probe or sample valve orientation.


1

APPENDIX F Leak Detection Technology Assessment Criteria.

1. Rate of false alarms and misses.

2. Instrument accuracy.

3. Personnel training and qualification requirements.

4. Ability to handle system size and complexity (including batch line factors).

5. Leak size or leak flow rate sensitivity.

6. Response time.

7. Leak size or leak flow rate versus response time.

8. Leak location estimation accuracy.

9. Release volume estimation accuracy.

10. Detection of pre-existing leaks.

11. Detection of a leak in shut-in pipeline pipelines.

12. Detection of a leak in pipelines under a slack line condition during transients.

13. Sensitivity to flow conditions.

14. Sensitivity to multiphase flow.

15. Retrofit feasibility.

16. System testing requirements.

17. System maintenance requirements.

18. Comparison of actual pilot test data with vendor’s system performance data.


2

APPENDIX G. Quarterly IMC Report Template

1. Executive Summary -Summarize the BPXA information and work reviewed in support of this report. -Identify and analyze any potential non-compliance with the terms of the Decree.

2. BPXA Performance: Section-by-Section Analysis -This part of the report shall provide a section-by-section analysis of BPXA’s compliance with the requirements of the Decree and recommendations for BPXA action to address any compliance issues. -Provide a citation to the relevant BPXA documents that support your analysis and recommendations. -In addition to the descriptions provided below, the IMC shall provide any other information and analysis necessary to assess BPXA’s compliance with the requirements of this Decree. General Compliance Requirements

• Emergency Repair Equipment and Materials: Describe whether BPXA is complying with each requirement of this Paragraph. Pipeline System-Wide Integrity Management Program

• Data and Information Collection -Describe whether BPXA has complied, or is on schedule to comply with each requirement of this Paragraph. -Describe what steps BPXA has taken to implement its plans and procedures for compliance with this Paragraph. -Describe whether and how BPXA has made the data and information available to BPXA personnel and agents. Comment on the effectiveness of BPXA’s efforts in this regard. -Describe any categories of data or information which are or appear to be missing from this program, and how, if at all, BPXA has made efforts to collect missing data or information or make conservative assumptions where data or information is not available.

• Pipeline Inspection -Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph. -Describe whether BPXA has selected and justified the appropriate assessment tools. -Describe whether the assessment schedule is consistent with the most current risk ranking. -Audit a sample of inspection data and report on whether data that indicates ongoing corrosion is being addressed and reflected in BPXA’s Risk Based Assessment and Ranking element.

• Risk Based Assessment and Ranking


3

-Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph. -Describe any categories of data or information which are or appear to be missing from the Risk Ranking, and how, if at all, BPXA has made efforts to collect missing data or information or make conservative assumptions where data or information is not available. -Describe whether and how the Risk Ranking is being updated as new or changed data or information becomes available.

• Risk Prevention -Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph. -Describe whether and how BPXA’s basis for selection of risk prevention measures takes into account the most current Risk Ranking and uses the content of the Data and Information Element.

• Continual Pipeline System Repair -Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph. -Describe whether and how BPXA is making use of all available data and information on the condition of its Pipeline System when scheduling repairs.

• Continual Program Improvement -Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph. -Describe whether and how BPXA is implementing its procedure for continual program improvement. Leak Detection

• LEOS Pilot -Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph.

• ATMOS Pilot -Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph.

• Technology Evaluation -Describe whether BPXA has complied, or is on schedule to comply, with each requirement of this Paragraph. -Describe whether the leak detection technologies BPXA studied pursuant to this Paragraph represents a complete list of available technologies. -Comment on BPXA’s conclusions about the applicability of leak detection technologies on the OTLs and upstream pipelines
